Downhole Environmental Risks Associated with Drilling and Well Completion Practices in the Cooper/Eromanga Basins
Damien Mavroudis
March 2001
Report Book 2001/00009 © Department of Primary Industries and Resources South Australia This report is subject to copyright. Apart from fair dealing for the purposes of study, research, criticism or review as permitted under the Copyright Act, no part may be reproduced without written permission of the Chief Executive of Primary Industries and Resources South Australia. 2 CONTENTS
Acknowledgments...... 6
Abstract ...... 7
Executive summary...... 7 Drilling fluid impacts ...... 7 Effectiveness of cementing for zonal isolation...... 7
Section One: Drilling fluids...... 8 Introduction ...... 8 Mechanisms of drilling fluid filtration...... 8 Filtration control materials and techniques...... 9 Bacterial contamination ...... 10 Drilling fluid contaminants ...... 12 Mud recap reports ...... 12 Clay swelling...... 15 Conclusion...... 15 Recommendations ...... 16
Section Two: Cements...... 17 Introduction ...... 17 Annular gas migration...... 17 Purpose of cementing...... 18 Primary cementing ...... 18 Problems arising from poor primary cementing ...... 18 Applications of API Cementing...... 20 Current cementing practices...... 21 Cement failure mechanisms ...... 21 Carbon dioxide effects on cement in well...... 21 Migration of gas through cement pore structure...... 22 Casing problem as part of the downhole risk study...... 23 High temperature chemistry of Portland cement ...... 25 Case history...... 27 Microannular formation in cements...... 27 Mechanism of shrinkage and expansion ...... 27 Long-term leaking oil wells ...... 28 Mud cake removal for cementing job ...... 28 Remedial cementing...... 29 Applications of the squeeze cement job...... 30 Cement plugs...... 32 Reasons for cement plug failure...... 32 Testing the quality of cement jobs ...... 34 Hydraulic testing...... 34 Temperature logging ...... 35 Communication tester ...... 35 Noise logging ...... 35 Acoustic logging ...... 35 Cement bond log ...... 35 Limitations of cement bond log ...... 39 Cement evaluation tool ...... 39 Acoustic properties of cement ...... 39 Channels...... 41 Fast formations...... 41
3 Preventative techniques...... 41 Prevention of gas migration ...... 41 Use of foamed cement...... 41 Foamed cement limitations ...... 43 Displacement properties of foamed cement...... 43 Use of flexible cements...... 43 Comparison of foam and flexible cements ...... 43 Durable zonal isolation (new cements)...... 44 Downhole corrosion prevention...... 45 Corrosive agents...... 45 Prevention methods...... 46 Corrosion testing...... 46 Conclusion...... 47 Monitoring well integrity...... 47 Cement time-scale...... 48 Fluid loss...... 48 Recommendations ...... 48
Appendix 1 ...... 50
Appendix 2 ...... 53
Appendix 3 ...... 55
Appendix 4 ...... 56
Appendix 5 ...... 61
Appendix 6 ...... 64
Appendix 7 ...... 66
Appendix 8 ...... 67
References ...... 68
FIGURES 1 The effect of drilling fluid invasion on a permeable formation...... 9 2 Structure of the CMC polymer molecule...... 10 3 Effect of biocide treatment...... 11 4a Downhole drilling fluid loss as a function of depth...... 13 4b Downhole drilling fluid loss as a function of depth...... 13 4c Downhole drilling fluid loss as a function of depth...... 14 4d Downhole drilling fluid loss as a function of depth...... 14 5 Objectives of primary cementing technique ...... 17 6 Mechanism for annular gas migration ...... 18 7 Common one-stage primary cement job on a surface casing string...... 19 8 Cement bond log response at time of cement placement and some time after ...... 22 9 Slurry dynamics immediately after placement...... 24 10 Della 1 cross section ...... 24 11 Compressive strength and permeability behaviour of neat Portland cement at 446°F...... 26 12 The accumulation of debris in well 14, SW Pannoniam Basin in Croatia...... 26 13 Defective primary cementing job...... 31 14 The mechanisms for cement cake build up in borehole...... 31
4 15 Circulation of cement in squeeze cementing ...... 32 16 The use of cement plugs for zonal isolation in the abandonment of a well...... 33 17 The use of a cement plug to prevent fluid loss to a thief zone...... 33 18 Dry test expectations and results...... 36 19 Typical temperature survey showing the probable cement top...... 36 20 Temperature composite profile log before cement squeeze...... 37 21 The configuration of a normal CBL tool run in the hole ...... 38 22 CBL interpretation chart ...... 38 23 CBL energy transmission as a function of microannulus wavelength...... 40 24 Sonic wave paths...... 40 25 Facilities for the generation of foamed cements...... 42 26 Life of the cement sheath for the three primary types of cements used ...... 44 27 Typical downhole arrangement of continuous corrosion inhibitor...... 47 A1 Relative static and dynamic filtration in the bore hole ...... 51
5 ACKNOWLEDGMENTS I thank my parents, George and Katarina, for their support and encouragement during the research, preparation and writing of this report. I acknowledge my summer vacation employer the Department of Primary Industries and Resources South Australia (PIRSA) and Supervisor, Michael Malavazos in the Petroleum Group of PIRSA for providing me with the opportunity and encouragement to undertake this project. His constructive guidance and comments throughout this project have been most appreciated.
Damien Mavroudis 2 March 2001
6 REPORT BOOK 2001/0009
DOWNHOLE ENVIRONMENTAL RISKS ASSOCIATED WITH DRILLING AND WELL COMPLETION PRACTICES IN THE COOPER/EROMANGA BASINS Damien Mavroudis This project reviewed literature in order to: • evaluate any downhole environmental risks associated with drilling fluids in the Cooper and Eromanga Basins; and • assess the effectiveness of cementing practices in achieving long term zonal isolation between reservoir formations penetrated by a well in these basins.
It was found that any potential drilling fluid contamination of Cooper and Eromanga Basin aquifers, in particular the Great Artesian Basin, is not a major concern.
Cementing and completion practices in the two basins are the main risks to the downhole environment. Many mechanisms are present to cause the cement to deteriorate. As a result, sufficient zonal isolation cannot be guaranteed for an infinite amount of time. The major risk associated with cement failure is cement carbonation.
A system employing the use of logging equipment was devised in order to evaluate whether the cement was meeting the criteria it was designed to achieve. Examples of the criteria that can be used to evaluate the integrity of the cement are postulated in this report.
EXECUTIVE SUMMARY • microbial contamination in aquifers; • contamination from biocides used to control This project reviewed literature in order to: microbial activity; • evaluate any downhole environmental risks • poor mud cake removal. associated with drilling fluids and completion practices in the Cooper and Eromanga Basins; From the review of the mud recap reports, the and most significant areas of fluid loss were in the • assess the effectiveness of cementing first 4000 ft of the well. The most likely reasons practices in achieving long term zonal for these losses were: unconsolidated Sands; and isolation between reservoir formations Clay Swelling. penetrated by a well in these basins. In any event it was determined that due to the DRILLING FLUID IMPACTS presence of the Bulldog Shale and its low Although an area of concern, drilling fluid impact permeability, an effective seal would be present to was found to constitute only a small portion of prevent the migration of drilling fluids into more downhole problems. The use of drilling fluids was environmentally significant formations. Although considered to be an issue because of the potential in deeper wells the fluid losses were difficult to to invade freshwater aquifers, particularly those quantify, it was concluded that the majority of the of the Great Artesian Basin (GAB). fluid loss was most likely to occur in to the producing zones of the formation. The main In order to determine the significance of fluid loss consequence of this is reservoir formation damage to the formations, mud recap reports were rather than an irreversible contamination of the reviewed. These reports record drilling fluid aquifer. Once brought ‘on-line’ a well will losses and provide an estimate of the depth and produce the majority of drilling fluid lost to the formation where this occurs. Other potential formation. impacts of drilling fluids include:
7 EFFECTIVENESS OF CEMENTING Apart from the potential to destroy the permeable FOR ZONAL ISOLATION zones, the real concern regarding drilling fluids was the possible contamination of underground The major area of concern was the effectiveness reservoir formations, particularly freshwater of cements in achieving long-term isolation in the aquifers such as the GAB in the Cooper and wellbore of individual formations penetrated by Eromanga Basins. Analysis of drilling fluid the well. Cements were identified as crucial impact involved an investigation into the: because they are currently the only means for • filtration properties that contribute to fluid zonal isolation in the wellbore. Zonal isolation is loss; deemed necessary in the wellbore because it • provides a means for the prevention of cross-flow zones in the wellbore where an increased rate through the wellbore. Such cross-flow is of fluid loss may be present; • considered to be a major risk for aquifer rheology of the drilling fluids; • contamination. study on the effects of different drilling fluids; • The effectiveness of cement zonal isolation in the typical mud composition; and wellbore was reviewed by investigating the • permeability of the wellbore environment. potential mechanisms of cement failure. The mechanisms identified were: It was realised at the outset of this project that an • high temperature; amount of drilling fluid is expected to be lost to • sour conditions/sweet conditions; the formation. In fact, it is good practice that a • bacterial presence; ‘controllable’ amount of drilling fluid be lost to • cement shrinkage; the formation because it enables the formation of a mud cake to prevent excessive fluid losses to the • formation damage; formation. The principal concern in terms of • poor mud cake removal; • drilling fluids was to determine where the major high cement permeability; and fluid losses occur. That is, in the zones where • cement carbonation (chemical reactions). freshwater aquifers may be present.
The findings of this investigation concluded: In order to determine where fluid loss occurs, it • cement carbonation and deterioration due to was necessary to review mud recap reports. hostile environments was the major Formations with higher permeability's are mechanism for cement failure; expected to lose a greater amount of drilling • it is necessary to establish a cement time- fluid. scale for which the cement should continue to provide zonal isolation to the formations Mechanisms of drilling fluid filtration isolated in the wellbore; • current cement technology may not be able to The potential impact of the drilling fluids lost provide long term zonal isolation and new stems from their uncontrolled invasion into technologies need to be considered; and reservoirs penetrated by the well. In particular, from an environmental point of view, the fluids • wells drilled through a successful drilling have the potential to contaminate any aquifer program will not always be accompanied by a present. Drilling fluid invasion can occur through competent cementing job. three main mechanisms: static, bit and dynamic filtration (see Appendix 1). SECTION ONE: DRILLING FLUIDS Of these mechanisms, dynamic filtration has been identified as the major means of drilling fluid INTRODUCTION invasion. Its effect on a permeable formation is Selection of a drilling fluid is a major component illustrated in Figure 1. If well integrity is in the drilling of a well. The success of a well maintained, fluid invasion will be confined to a often depends on the performance of a drilling small region in the formation. In cases where well fluid (Darley and Gray, 1991). integrity is lost, a significant invasion into the formation may occur. As part of examining the downhole environmental risks associated with drilling practices in the Cooper and Eromanga Basins, consideration was given to the potential impact of drilling fluids. 8 Figure 1 The effect of drilling fluid invasion on a permeable formation (Darley and Gray, 1991)
Filtration into the formation occurs in three steps: in the formation of a mud cake under the dynamic • An external mud cake attached to the walls of filtration mechanism. There are several colloidal the borehole. materials available that can be used to control • An internal mud cake, about 2–3 grain fluid loss properties of water-based mud. The diameters into the permeable formation. following products are the most commonly used • A zone that has been invaded by smaller in drilling applications. particles during the mud spurt period. This invasion zone can typically extend about an Lamellar inch into the formation. This zone is typically Lamellar material controls filtration by aligning damaged because of pore blocking by the themselves with the normal flow of mud into the finer invasive particles. This invasion makes formations. This helps to produce highly the recovery of hydrocarbons very difficult compressible filter cakes. Bentonite is an example due to the reduction of the permeability near of a lamellar material. the borehole. Fibrous The mud cake will only form once a primary Fibrous material is squeezed into the formation blockage of the pore spaces has begun. This then where it helps to block the formation and create gives the finer particles a basis to form a mud bottlenecks. This material tends to produce deep cake. Particle size distribution has a very penetration and can be difficult to remove. Filter important role in forming a low-permeability cakes from such materials are incompressible. filter cake. If there are too many large particles Attapulgite is an example of a fibrous material. then the bridge will build too quickly and will form a filter cake that is shallow and thin. The Granular subsequent filtration loss will be high. This is known as filtrate damage. If the particle Granular materials enter the formation and block distribution is too small then the bridge will not any pores smaller than three times their size. This build quickly enough and the mud solids will tends to cause shallow solid penetration but, penetrate deep into the formation and cause because of their rigid structure, can also allow for damage. deep filtrate invasion. They tend to form rather incompressible filter cakes. Barite is an example of such a material. Filtration control materials and techniques Emulsion Where excessive fluid losses are likely to occur, Emulsions tend to control filtration by entering material can be used to minimise fluid loss and pores and causing increases in capillary pressures maintain wellbore integrity. These materials assist for fluids to enter. These types of materials do not
9 form filter cakes. For example, an oil emulsion and may result in a loss in the rheological will decrease permeability to water without properties of the mud. affecting permeability to oil.
As mentioned, mud additives provide protection against water loss through three basic mechanisms: binding of free water, blocking pores and forming a tight filter cake. The carboxymethyl cellulose (CMC) polymer as well as bentonite has the ability to chemically bind water to the polar sites on the clay platelets or to the polymer molecules and form a tight impermeable layer. Mud additives are effective because they bond all of the free water and make it difficult for the water to escape from the Figure 2 Structure of the CMC polymer molecule drilling mud. By binding the water the viscosity (Darley and Gray, 1991) of the mud also increases and the mud becomes more resistant to flow into the porous formation. Microbial activity in drilling muds can be The benefit of using bentonite and CMC is that influenced by several features in the drilling both of these substances have the ability to build environment. Warm temperatures and high an impermeable membrane over the porous nutrient content in the mud tanks can have formation. undesirable effects in which bacterial growth is enhanced. The process of removing the drill BACTERIAL CONTAMINATION cuttings (shale shakers) can further increase the The communication between surface and oxygen content of mud, which is favourable for subsurface oilfield environments is, of course, the growth of bacteria. initiated by the drilling process. Drilling requires the circulation of fluids from the surface to the bit Ezzat et al. (1997) identified bacterial to help carry cuttings out of the borehole and to contamination as causing the following problems: • control formation pressures in the borehole. In microbiological corrosion of well tubulars this process, chemicals and microbes from the and screens; surface are circulated into the deep subsurface • biomass plugging in injection wells and in the energy-rich oil-bearing strata and hydrocarbon- formation; and laden cuttings are brought into the oxygen-rich • hydrogen sulphide production deep in the moderate temperature surface environment. formation, leading to reservoir souring. Through this mechanical process microbiological activities can be initiated in surface and Apart from this, the potentially hazardous nature subsurface environments. This does not occur of the bacteria if they contaminate a freshwater normally and can lead to the bacterial aquifer needs to be addressed. This will be contamination of aquifers. considered in a further investigation for the project. Water-based drilling fluids often contain organic polymers which act as viscosifiers and fluid loss Given the additives present in the drilling muds, control agents. CMC is one example (Fig. 2). microbial activity is significant due to the These organic polymers, which tend to be of plant presence of xanthan gums, starch, CMC, or microbiological origin, can be degraded and hydroxyethyl-cellulose etc. Biodegradation of used as a food source for the growth of naturally drilling mud additives results in significant occurring oil-field bacteria. This can occur microbial growth within the mud. This can raise despite the addition of biocide materials for the the bacteria to a level that may be harmful. This hampering of microbial activity. Microbial increase is known to affect the wellbore growth in the mud can result in contamination of adversely. the well and near-wellbore zone (Ezzat et al., 1997). Fouling, corrosion and reservoir souring Even with a limited amount of fluid loss during may then occur during subsequent operations. If drilling, the bacteria would accumulate in the near bacterial growth is extensive, significant wellbore zone. Microbial activity would continue consumption of the organic polymers can occur during ‘shut-in’ periods and would be supported 10 by the soluble, carbon-based nutrients from the possible migration of water-borne bacteria should drilling mud. Under oxygen-depleted conditions be considered in detail. A study of the methods the activity of anaerobic sulphate-reducing for controlling bacteria should also be considered, bacteria would increase, which might have a large with the intention of analysing the validity of effect on the wellbore. bacteria control techniques for water treatment. The presence of bacteria can also be hazardous to It is important to consider the long-term effects the casing of a well through the introduction of that bacteria may have on the wellbore sulphate-reducing bacteria. Hydrogen sulphide environment. If left untreated, it is possible that can cause corrosion of the casing (metal the microbial activity may cause a breakdown of imbrittlement) (Ezzat et al., 1997). The effect of the downhole integrity. bacteria in freshwater aquifers used for agricultural use or consumption is not yet known. Bacteria can invade the formation in the close vicinity of the wellbore. Bacteria left here can The use of bactericides for controlling bacteria result in a poor cementing job due to microbial should also be investigated. Bactericides are activity. Thus there can be an adverse affect on simply poisons that kill living organisms and kill the wellbore characteristics and the purpose of the micro-organisms, including sulphate-reducing primary cementing job would have been defeated. bacteria, slime-forming bacteria and algae. These Therefore it is important to consider using mud micro-organisms attack polymeric drilling muds, that does not promote the increased activity of completion and workover fluids, slick waters and bacteria. Such drilling fluids employ high salinity, fracturing fluids. They can cause a deterioration high pH and biocides to curb the microbial of the fluid system and reduce the effectiveness of activity. the well treatments. Figure 3 depicts the effect of biocides on general aerobic bacteria. After the The major concern with the presence of bacteria prescribed biocide concentration has been in the drilling fluid is with the potential reached, further increases in the concentration contamination of freshwater aquifer supplies that levels do not affect the bacteria. could be consumed by humans or livestock. The
Figure 3 Effect of biocide treatment (Ezzat et al., 1997)
11 DRILLING FLUID CONTAMINANTS XC Polymer The following is a list of the chemicals typically Xanthan gum biopolymer (bacterially produced used in drilling fluids in the Cooper and polymer) Eromanga Basins (Bowyer, 1994), these XP-20 compounds are considered to be non-toxic Chrome lignite (Schlumberger, 2001). Mud recap reports Aquagel Mud recap reports were investigated to determine Bentonite the areas where the most significant amounts of Barite drilling fluids were lost (Appendix 2). Although Barium sulphate, a mineral used to increase the the number of reports considered was a small weight of drilling fluid sample of the total number of reports, they were a Benex substantial aid to determining a perspective of Bentonite extender where the major fluid losses occur. Consultations Bentonite with field experts and other individuals tended to Clay containing smectite as the essential mineral confirm the findings from those reports. • presents a very large total surface area • characterised either by the ability to swell in As can be seen from the data set (Appendix 2) water or to be slaked and to be activated by and the plotted charts, relatively large amounts of acid drilling fluids are lost in the first 4000 ft of a • used chiefly to thicken oil-well drilling muds formation (Fig. 4 a–d). Also, large losses occur CMC between 8000 and 11 000 ft. The consequences of Carboxymethyl cellulose (sodium) the losses are discussed in the conclusion of this Dextrid section. Organic polymer Durenex Mud recap reports were used to determine: Resin additive/organic polymer • whether significant amounts of drilling fluids Gel were being lost; and Bentonite • if major losses were occurring, that they were Lignosulphonate not in areas of environmental importance. Member of the lignin family of organic polyelectrolytes The reports describe the surface and downhole • modified lignosulphonates may be sodium, fluid losses associated with drilling activities. calcium or chromium treated types Losses of 500 bbl or more of drilling fluid were • as a direct consequence of the ability of not uncommon in some wells. Losses at this depth lignosulphates to adsorb on clay surfaces, (4000 ft) may not be of major environmental they are used as an anti-corrosion agent and concern as the Bulldog Shale should provide stabiliser of oil-in-water emulsions. adequate isolation of the top formation layers. PAC These large losses can be explained by: Polyanionic cellulose – a long chain polymer of • unconsolidated sands; and high molecular weight • shales in the layers swelling and adsorbing a • can impart viscosity or reduce water-loss great deal of drilling fluid. properties to the drilling fluid of either freshwater or saltwater muds Fluid losses beyond the GAB tend to vary with PHPA wellbore depth and the type of formation being Partially hydrolysed polycrylamide drilled. In an environmental sense, losses to this Polyacrylamide section of the formation are not of major Organic polymer significance. The bulk of the fluid losses to this Q-Broxin region are most likely to be produced when the Modified lignosulphonate wellbore is brought on-line. Therefore, little to no Soda ash drilling fluid will remain in the formation. Commercial term for sodium carbonate (Na2CO3) Moomba wells seem to have a fluid loss in the Spersene 6000–9000 ft interval, whereas losses in other Modified lignosulphonate wells can be expected in the 8000–11000 ft Vertoil interval. Primary emulsifier 12 250
200
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Moomba 118 Moomba 119 100 Moomba 125 Moomba 126
Downhole Fluid Loss (bbl) 50
0 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000
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Figure 4a Downhole drilling fluid loss as a function of depth
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Moomba 128 300 Moomba 134 Miluna 21
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Figure 4b Downhole drilling fluid loss as a function of depth
13 300
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150 Burke East -1 Moomba 114 Moomba 115 Moomba 116 100 Downhole fluid loss (bbl)
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0 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000
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Figure 4c Downhole drilling fluid loss as a function of depth
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80 Moomba 98 Dullingari-50 Brumby-9 60 Grenache-1 Drilling Fluid lost (bbls) 40
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Figure 4d Downhole drilling fluid loss as a function of depth
14 However, fluid losses in these regions are not as Evidence exists that water molecules adsorbed significant as those experienced in the surface directly on clay mineral surfaces and for some formations due to the higher degree of distance outward have an organised arrangement, compaction of this deep formation. much like that of ice (Grim, 1968). The degree of bonding to the clay mineral surface reflects the Of interest, however, was the drilling fluids degree of swelling of the clay. That is, the high survey conducted by APPEA (Appendix 3). water bonding between the clay and the water APPEA listed the volumes of drilling fluids lost reflects a greater degree of clay swelling downhole: it reported a value of 5789 m3 lost to (Chilingarian, 1981). formations drilled in 1996. However, independent research and a review of the mud recap reports Consideration needs to be given to the clay indicated a value of 6015 m3 for 1996 for swelling properties of rocks. Rock clays can block downhole fluid losses for Santos alone. The the wellbore and prevent the flow of reason for this discrepancy is unclear. hydrocarbons because of their relative large surface areas. The degree of hydration of clays in The GAB, on average, tends to start at around the the vicinity of the wellbore can affect the 5000 ft mark. Shallow aquifers are found mainly efficiency of primary production and secondary in the upper formations. As they are not used as a recovery. Although clay swelling in the wellbore potable water source, fluid losses in this area are is not a consideration in the environmental sense, not a major concern, particularly if the Bulldog it does pose a problem for treating zonal isolation Shale is effective in providing upper zonal issues in any possible remedial action. In this isolation. Significant interest in possible case, swelling may be an issue by not permitting contamination in the GAB exists and steps to re-entry of the hole for log runs, maintenance or avoid contaminating its aquifers are necessary remedial work. because the GAB is important for commercial and life-supporting activities. CONCLUSION The effects of drilling fluid on the downhole Clay swelling environment are not of major concern. This Clay swelling has been identified as a reason for conclusion was reached from the evidence fluid loss in the upper areas of a well. For this relating to the zones where fluid losses occurred. reason, it is important describe the method in The fact that large losses are encountered mainly which this water adsorption occurs. in the top 4000 ft of the formation is not of major concern if the sealing qualities of the Bulldog Clay properties are a function of: Shale are adequate. Those properties need to be • structure; investigated further for a firm conclusion to be • quantities of exchangeable cations; and reached. In addition, losses into deeper producing • chemical composition. formations are not considered environmentally significant because the majority of drilling fluid Barshad (1955) discussed the subject of the will be expelled from the formation upon the relationship between adsorption of water (and initiation of production. Furthermore, the swelling) and properties of the clay–water components present in the drilling fluid do not systems. Two types of clay swelling were raise any significant concerns regarding toxicity. realised. The first type is due to the crystal lattice However, when wellbore integrity is itself (interlamellar or interlayer expansion). Na- compromised a potential concern does exist montomorillonite exhibits this type of swelling. because excessive amounts of drilling fluid could The second type of swelling is due to the be lost. adsorption of water on the surfaces of the clay particles. Fluid losses in the shallower formations (above 4000 ft) are a result of two primary mechanisms: Some clays, for example kaolinite, do not swell • unconsolidated sand; and upon hydration. Na-montorillonite clays, • clay swelling. conversely swell in water to many times their initial dry volume. Calcium and magnesium It is postulated that the primary reason for fluid montmorillonites and illites have intermediate loss is the unconsolidated sand and lack of swelling characteristics. compaction in the upper formations. Compacting forces are a function of depth: they increase as 15 depth increases. This means that it is easier for Further study should be conducted into the types drilling fluids to penetrate surface formations and use of biocides in the treatment of bacteria because of the lack of overburden pressure. infected waters. This information should provide Therefore, relatively large amounts of fluid loss ‘safe’ limits for human beings. It should also are expected. Clay swelling is also important, include a study into the amounts of biocide particularly in the thick shale areas encountered in currently being used in the field with the Cooper and Eromanga Basins. consideration being given to nearby water wells that may be contaminated by a biocide. However, what should be considered is the Examining the hydrodynamics of the GAB may proximity of oil wells to consumption water be useful for estimating potential dispersion rates. wells. Although drilling fluid lost to the formation is not likely to affect distant water wells, A study into the validity of slimhole technology contamination may occur in water wells that are should be considered. Use of slimholes is nearby. This is also a consideration when beneficial because smaller volumes of drilling implementing the use of biocides. fluids are used and thus the fluid losses to the downhole environment could be reduced. Some concern has been expressed (Ezzat, et al., Furthermore, slim-hole rigs are likely to leave a 1997) over the possibility of bacteria growing in smaller surface indications: this environmental water storage tanks at well sites. It is possible that consideration is outside the scope of this report. bacteria may have sufficient time to accumulate in stagnant water deposits. This could cause The use of underbalanced drilling muds in problems if introduced to the drilling mud. It may depleted sands should be considered as a means be necessary to use bactericides in these tanks to for reducing the fluid losses to the formation. It ensure that the bacteria is killed before the water may be a consideration that in production, where is used with the drilling fluid. Acceptable control the geology is known, underbalanced conditions limits should be followed when using could be used to prevent excessive losses in the bactericides. Regulation may be necessary. first few formation layers, especially in the GAB. Bacteria introduced to the aquifers can pose Production wells in the Cooper and Eromanga problems if the water is produced at some later Basins are drilled into depleted sands. Typical stage by a water well intended for human virgin pressures in the Moomba area are 4200 psi: consumption. The increased presence of bacteria depleted sands in this region exhibit depleted could lead to health problems and could be pressures of approximately 2100 psi. Sufficient significant, especially when bacteria levels exceed well control could be achieved with an ‘safe’ limits. underbalanced mud and an experienced drilling crew. Another difficult matter is the introduction of foreign bacteria into the wellbore environment. The geology of the Bulldog Shale should be The effects of introducing surface-bound bacteria investigated further. Areas where the shale may to the underground formations through the be thin or not present are points of concern drilling process was not investigated in this study. because they may lead to cross-flow in the The potential for problems arises since it is not formation. Such areas should be identified. There known whether bacteria introduced to the may be points in the shale where it is thin enough wellbore may thrive in such conditions thereby to cause problems of cross-flow and thus increasing the risk of aquifer contamination. contaminate the formation itself.
RECOMMENDATIONS A more stringent means of fluid accounting Arising from these conclusions, a study should be should be maintained in the field. While it is initiated into the potential for aquifer realised that recording fluid loss to the formation contamination through bacterial activity. Also, the is difficult, a more precise means of fluid type of bacteria likely to be present in the recording should be investigated. wellbore should be investigated as those present may not pose a significant health risk. Such a A review on the use of bactericides in wells study should also consider the mobility rates of should be pursued. Standards need to be set so bacteria which might enter a major aquifer such that biocides and bactericides are not used as the GAB. excessively. An excessive use of biocides would result in elevated concentrations in the drilling
16 fluids. If freshwater did become contaminated, significant in well completions as well harmful or lethal concentrations of biocides might productivity is improved and more control over be present in water intended for agricultural use the well is achieved. or livestock consumption. It is not known what concentration of bactericides are harmful for livestock or human consumption. The potential for biocide-contaminated formation waters to transfer to a water well is also not known. Such issues warrant further study.
SECTION TWO: CEMENTS INTRODUCTION This section considers the cementing practices and techniques currently employed in the Cooper and Eromanga Basins. Cementing is the most important part of the well completion and abandonment phase of the well. The integrity of the cement and the properties that it exhibit are not only important at the time of cement placement but also for many years after Figure 5 Objectives of primary cementing abandonment. Ensuring adequate isolation within technique (Smith, 1986) the wellbore of the reservoir sands that are known not to be in natural hydraulic communication within the reservoir is a key objective specified in Annular gas migration the ‘Statement of Environmental Objectives for Fluid migration may occur during drilling or well Drilling in the Cooper/ Eromanga Basin’ (PIRSA, completion operations. Inadequate sealing of 2000). varying formations in the wellbore can lead to the migration of gas. This migration occurs through The use of cement is the only current means of the invasion of formation fluids into the annulus establishing zonal isolation within wellbores, and is caused by a pressure imbalance at the either through cement behind the casing or plugs formation face. The fluids can flow to a lower between the zones. The number of ways identified pressure zone and, in some cases, to the surface for cement breakdown to occur means that cement (Fig. 6). is not an effective means for long-term zonal isolation. In areas where ideal conditions are Fluid migration from high pressure zones to those present cements may provide sufficient long-term of lower pressure can lead to the contamination of zonal isolation, although the period of time has these zones. However, extreme gas accumulation not yet been identified. due to large pressure imbalances can cause blowouts. The following causes of cement deterioration identified by Marca (1990) are addressed in this The severity of gas migration is not always section: apparent. Gas migration after primary cementing • high temperature; can adversely affect the wellbore and evidence • sour conditions/sweet conditions; may only be noticed some time later. Remedial • bacterial presence; cementing procedures are thus required to correct • cement shrinkage; such problems. • formation damage; Gas migration between zones, which does not • poor mud cake removal; build up at the surface, is difficult to detect. Gas • high cement permeability; and • migration may cause the following problems cement carbonation. (Sutton et al., 1989): • impaired gas production; Since the first use of cements in wells in 1903 • filling of the above depleted zones; and (Smith., 1990), the use of cement has been very • important in isolating different zones within oil, the effectiveness of stimulation treatments gas and water wells. Zonal isolation is very may be reduced. 17 Figure 6 Mechanism for annular gas migration (Parcevaux et al., 1990)
It is possible to evaluate the degree to which Primary cementing downhole channelling occurs by the use of Primary cementing is the process of placing logging tools such as noise and acoustic logs. cement in the annulus between the casing and the Hydraulic communication testing is not formations exposed in the wellbore. The objective recommended because the potential exists for of primary cementing is to achieve zonal creating communication across effectively isolation. By this it is meant that the mixing of cemented zones and minor defects in the primary zones such as water and oil or a freshwater cementing job can be aggravated. aquifer with a saline one is prevented. This is achieved by forming a hydraulic seal between the When the gas migration problem was first casing and the cement and between the formation recognised it was thought that it resulted from and the cement (Fig. 5). At the same time it is poor mud removal properties. As has been seen, necessary to prevent fluid channels in the cement poor mud removal does not allow for adequate sheath. In many instances the full production bonding at the casing/cement/formation potential of a well may not be reached if complete interfaces. This can lead to the development of zonal isolation is not achieved. Sufficient zonal channels for fluid migration. Although other isolation ensures that the environmental causes of fluid migration have been recognised, objectives in drilling the well are met the principal cause stems from a mud removal (Appendix 3). problem. This is due to the continuous mud channels in the annulus between two permeable Problems arising from poor primary zones favouring annular flow. cementing PURPOSE OF CEMENTING Several problems inherent in a poor primary cementing job have been identified by Burdylo This section of the report presents information on: and Birch (1990): • the various purposes of cement, namely • the well will never reach its full production primary and remedial cementing; potential; • the failure mechanisms of cement; • subsequent efforts to repair the cementing job • the testing quality of cements jobs; and • may actually end up causing irreparable the preventative techniques. damage to the formation;
18 Figure 7 Common one-stage primary cement job on a surface casing string (Burdylo and Birch, 1990)
• lost reserves; Cement time-scale • lower production rates; The cement time-scale refers to the period of time • stimulation treatments may not be able to be that the cement must provide an adequate confined to the producing formation; hydraulic seal between the formations penetrated • difficulty in confining secondary or tertiary in the wellbore. What needs to be addressed is a fields to the pay zone; suitable time-scale for the life of the cement. • aquifer and reservoir damage from potential Imposing a time limit is difficult. However, as a cross-flow; and minimum, the cement should provide adequate • potential contamination of aquifers utilised as zonal isolation for the life of the producing well. a resource. In abandonment an inactive well will need to provide sufficient zonal isolation to prevent cross- The latter two issues are relevant to this report. flow. If it is found that isolation is not achieved, then a means for providing continued zonal Zonal isolation isolation should be considered. This may require a The primary cementing job is intended to provide continued well maintenance program, especially adequate zonal isolation of the formations for wells drilled in highly sensitive areas. penetrated. Inadequate zonal isolation provides a means for cross-flow between the communicating Classes of cements formations. This is not desired because it provides The choice of the correct cement is crucial in a means for aquifer contamination, continued achieving satisfactory isolation. The properties of cross-flow and, perhaps, a mechanism for natural these types of cements are detailed in Tables 1 pressure depletion. and 2 (Course Notes PTRL 3017, 2000).
This report focuses on the downhole environmental risks, that is the risk of contamination of freshwater aquifers resulting from current and continued cross-flow in the formation. In particular, the possible contamination of the GAB is a very significant issue not only because of commercial interests but also because the basin has major environmental significance. 19 Table 1 Cement components used in typical class cement API Class Compounds % Fineness Water/cement
C3SC4AF C3AC2S (sq cm/g) ratio A 53 8 8 24 1500–1900 0.46 B 47 12 3 31 1500–1900 0.46 C 70 13 3 10 2000–2400 0.56 D 26 12 2 54 1100–1500 0.38 G 52 12 8 32 1400–1600 0.44 H 52 12 8 32 1200–1400 0.38 J 53.8 – 38.8 – 1240–2480 0.44
Table 2 Function of cement components Compound Characteristics
Tricalcium aluminate/C3A • Promotes rapid hydration
(3CaO • Al2O3) • Affects the initial setting and thickening time of the cement • Makes the cement susceptible to sulphate attack
Tetracalcium aluminoferrite/C4AF • Promotes low-heat hydration
(4CaO • Al2O3 • Fe2O3) Tricalcium silicate/C3S • Major component produces most of the cement
(3CaO • SiO2) strength • Responsible for the strength that the cement develops early in its life
Dicalcim silicate/C2S • Hydrates slowly
(2CaO • SiO2) • Has the properties of slow, small gradual gain in strength over a period of time
Applications of API cements API cement D, E In order to improve the chance of effective zonal • class D at a depth range of 6000 to 10 000 ft; isolation it is necessary to use the correct cement E at depths of 10 000 to 14 000 ft for the specific well environment. • class D used at temperatures of 170 to 260oF; and class E used at temperatures of 170 to API cement A 290oF • • typically used a depth of between 0 and used when fairly high temperatures and 6000 ft pressures are encountered o • • used at temperatures up to 170 F more expensive than Portland cement • • used when special properties are not required available in types that exhibit high resistance • use of this cement favoured since it is the to sulphate most economical of all cements API cement F API cement B • used in the depth range of 10 000 to 16 000 ft • o • can be used at depths between of 0 and used at temperatures of 230 to 320 F 6000 ft • used in cases of extremely high temperature • intended for use when moderate to high and pressure sulphate resistance is required (well • types include moderate and high resistance to conditions permitting) sulphate • used at temperatures up to 170oF • an economical cement API cement G, H • used in depths between 0 and 8000 ft API cement C • temperature range up to 200oF without the use • same depth and temperature range as class A of modifiers and B cements • basic cement compatible with accelerators or • used when high early strength is required retarders • • high in tricalcium silicate additives can be blended in at bulk station or at job site
20 API cement J Lead Slurry Tail Slurry • used at depth ranges of 12 000 to 16 000 ft Bentonite 6% BWOC 0.15 gal/sacks • intended for use under conditions of extreme Litefill 25% BWOC 0 temperature and pressure 170 to 320oF CaCl2 1% BWOC 0 unmodified Anti-foam 0.01 gal/sacks 0.01 gal/sacks • properties are such that it will not set at a Dispersant 0 0.15 gal/sacks temperature of less than 150oF Retarder 0 0.04 gal/sacks • useable with accelerators and retarders Production cement 219 sacks of class G cement followed by 179 Current cementing practices sacks of class G tail slurry. Cementing techniques in the Cooper and Eromanga Basins generally use class A cement in Lead Slurry Tail Slurry the surface casing and class G cement in the Silica flour 35% BWOC 35% BWOC production interval. Two case studies are Uni-FLAC 0.6% BWOC 0.7% BWOC presented in this section to illustrate the cement Bentonite 16% BWOC 0 properties utilised in the Cooper and Eromanga Anti-foam 0.01 gal/sacks 0.01 gal/sacks Basins. Both wells are located in the Della field: Dispersant 0 0.1 gal/sacks Della 7 reached a true vertical depth (TVD) of Retarder 0 0.01 gal/sacks 6700 ft on February 1980 and Della 20 reached a Retarder aid 0.06% BWOC TVD of 6623 ft on April 2000. Stabiliser 0.55% BWOC
Della 7 The most significant difference in the cementing Surface cement techniques between the two wells was the 410 sacks of class A cement were used to cement production cement. It is surprising to see that in the surface casing in place. This cement had the the older well, Della 7, class F cement was used. following properties: Class F cement is used in areas of high Slurry weight: 15.6 ppg temperature and pressure. It also offers moderate Thickening time: +3 hours to high sulphate resistance. Class G cement, as Water requirements: 4.87 gals/sack used in Della 20, does not have the high Slurry volume: 1.1 ft3/sack temperature and sulphate resistant properties of Production cement class F cement, but it is likely that the cement 200 sacks of class A cement were used to mix additives are adequate in fulfilling the purposes with: for which the cement was designed. Class G • 4.0% Bentonite by weight of water cement is used because it offers faster thickening This was followed by 160 sacks of class F cement time and increasing versatility. Class F cement is mixed with: more costly as it is imported and its use is now • 15% salt by weight of water limited to wells that require the specific class F properties. Production casing cement requires that the following properties are maintained: Two questions arise from this finding. Does the current class G cement offer any Class A Class F advantages/disadvantages over the old class F Slurry weight 11.8 ppg 16.2 ppg cement? If so, what are they? Answers to these Slurry volume 2.4 ft3/sacks 1.0 ft3/sacks questions are beyond the scope of this report. Water requirements 15 gal/sacks 4.3 gal/sacks CEMENT FAILURE MECHANISMS Carbon dioxide effects on cement in Della 20 well Surface cement Carbon dioxide can corrode cement through a 174 sacks of class A and a tail slurry of 85 sacks series of chemical reactions. The process is of class A cement: known as cement carbonation and is often the most likely cause of cement deterioration. Over time the carbon dioxide can corrode the cement; Thus zonal isolation and loss of casing will occur.
21 According to Bruckdorfer et al. (1986) the primary mechanism by which cement corrosion occurs, is:
+ - CO2 + H2O <-> H2CO3 <-> H + HCO3
+ - Ca(OH)2 +H + HCO3 -> CaCO3 + 2H2O
+ - C-S-H gel + H + HCO3 -> CaCO3 + amorphous silica gel
CO2 + H2O +CaCO3 <-> Ca(HCO3)2
Ca(HCO3)2 + Ca(OH)2 <-> 2CaCO3 + 2H2O
When excess carbon dioxide is present, calcium carbonate is converted to calcium bicarbonate, which is water soluble. Calcium carbonate can migrate out of the cement matrix because of this. The dissolved calcium bicarbonate can then react with calcium hydroxide which goes to form calcium carbonate and fresh water. The resultant water could go on to dissolve more calcium bicarbonate. Thus the overall result is a leaching of cement materials from the cement matrix. This leads to an increase in porosity and permeability Figure 8 Cement Bond Log response at time of and a decrease in compressive strength. Corrosion cement placement and some time after. of the cement by carbon dioxide is Represents the difference in CBL responses at thermodynamically favoured and it can not be time of cement placement right, 1983 and some time after re-evaluation left, 1998 (Krilov et al., prevented. 2000) Figure 8 the amplitude response data from the cement bond log clearly shows the loss in cement The extent to which cement shrinkage is a bonding. Although the cement bond indicated by significant problem is difficult to determine. The the log (at time of placement) showed a relatively time factor is important because shrinkage is due good bond, the later log at the same depth to cement hydration which continues with time. indicates poor cement integrity which ultimately As cement begins to set and the hydration results in poor zonal isolation behind the casing. accelerates, an increase in intergranular stresses is The log can also provide evidence of cement experienced due to the growth of calcium silicate degradation and deterioration and possible hydrates. The mechanism for such growth is not migration of crushed fragments from the annuli to be discussed in this report. Cement hydration is the wellbore, leaving free space behind casing. responsible for an absolute volume reduction of the cement matrix and is often known as chemical The bond of the cement to the casing or the contraction. Normal Portland cement can formation interface is affected by: typically expect a volumetric shrinkage of 4.6%. This phenomenon, reported in many civil • the bulk volumetric shrinkage of the cement; engineering cases, is due to the volume of the • the lack of casing and formation roughness; • hydrated phases being less than that of the initial a mud film or channel at the interface; reactants. • a free water channel or layer in deviated wells; Migration of gas through cement pore • excessive downhole thermal stresses; and structure • excessive downhole mechanical stresses. Guyvoronsky and Farukshin (1963) were the first to introduce the concept of gas migration through the pore structure of a very permeable gelled or set cement. Then Cheung and Beirute (1982)
22 proposed a mechanism indicating that the gas first cemented in place over the bottom 1000 m. invades the cement pores and then permeates the Production casing was suspended within the entire cement matrix, consequently preventing the casing spool on the ‘Christmas tree’. The final hydration process from closing all of the pore step was running the production tubing down the spaces. Parcevaux (1984) was able to prove the production casing and centralising it with a existence of free porosities. These were composed packer. This acted as a barrier between the of well-connected pores which began to appear formation and the surface. upon the initiation of the setting period. In fact, he stated that gas migration is driven by the unsteady On 16 September 1987 gas was seen venting permeability effect through the cement pores. through a 2 x 2.5 m crater about 30 m from the Following the primary enlargement of the cement wellhead. As a result of a wireline run, it was pores, a pseudo-steady state is achieved when possible to ascertain that both the production communication has been established throughout tubing and the production casing had parted at the the cement column and gas channels have reached 35 m mark. a stable size. The degree of failure in Della 1 meant that it was Figure 9 shows that immediately after placement not possible to remove the surface casing, the the slurry behaves as a fluid and transmits production casing or the production tubing for hydrostatic pressure. A compensation of examination. What needed to be addressed was volumetric changes due to hydration and fluid the issue of whether or not this was an isolated loss is accomplished by a reduction in the height event or if concerns for other wells in the Cooper of the cement column. Continued fluid loss from Basin were warranted. The factors leading to the the slurry, as well as hydration, results in the blow-out needed to be determined and criteria for development of a gel structure that causes the the assessment of other wells needed to be cement to lose its ability to transmit fluid established. pressure. At this stage it is possible for the pressure to drop and become less than the gas Martucci (1989) reported on the factors which pressure. A potential for gas flow now exists. could have put Della 1 at considerable risk: During this stage the cement becomes self- • limited allowance for external corrosion due supporting and further hydration causes a further to the fact that no intermediate casing was decrease in pressure. The gel structure restricts present; pressure as the cement slurry thickens with time. • the cement sheath around the surface casing Gas flow can be inhibited by the formation of was incomplete at between 15 and 90 m, strong bonds between cement particles which leaving part of the casing open to corrosion reduces permeability. The critical area is from the formation; indicated by the shaded region in Figure 9. • the steel in the N–80 production casing used over the upper part of the well is more Casing problem as part of the susceptible to carbon dioxide attack than J–55 downhole risk study casing; Casing corrosion in the cooper basin • it was an old well cased and suspended after drilling in 1970; and A consequence of the failure of a cement job • behind casing is the exposure of the casing to there was no system for cathodic protection corrosion mechanisms. To illustrate this the blow- present at the time of drilling the well. out of Della 1 in 1987 is discussed and the reasons behind this blow-out are investigated. At Based on of these factors, the following the time it was suspected that the production assessment criteria were recommended for other tubing, production casing and surface casing all wells that are deemed to be at a potentially higher failed at the 35 m mark below the surface risk of critical failure (Martucci, 1989) • (Martucci, 1989). no intermediate casing present; • wells with production casing/production In the Della 1 cross-section (Fig. 10), a 12 1/4 in; tubing annulus pressure that is less than diameter hole is bored and the 9 5/8 in. surface 1.7 Mpa. casing, which has a depth of 300 m, was • wells more than five years old; and cemented in place. A concentric hole was then • testing the nature of soils. drilled within the surface casing to total depth and the 7 in. production casing was then set and 23 Figure 9 Slurry dynamics immediately after placement (Bannister et al., 1983)
Figure 10 Della 1 cross-section (Martucci, 1989)
24 In regards to the second point, the use of EUE It is likely that the corrosion was due to corrosive tubing does not guarantee leak prevention of gas chemicals present in the drilling mud being left in from the screwed joints. Over a lengthy period, the well at the time of completion. Formation gas would leak from the screwed joints into the waters containing corrosive compounds were also production casing/production tubing annulus. A a possible reason for the failure, particularly high annulus pressure would indicate the lignosulphates in the mud which can decompose soundness of the production casing and a low to release CO2 and H2S. It should be recognised annulus pressure could signify the possibility of a that unless there are substantial amounts of CO2 perforated production casing. In the case of the and H2S, lignosulphates are not likely to cause the fourth point, the soils in the Della field were high corrosion rates observed. corrosive. In many instances buried flowlines have failed 3 to 5 years after operation. This High temperature chemistry of indicates how quickly corrosion can take place. Portland cement Portland cement is basically a calcium silicate Under the criteria, 42 wells were considered to be material. When water is added, the tricalcium at an elevated risk. Following further silicate (C S) and dicalcium silicate (C S), the consideration this figure was revised to 67 wells. 3 2 two major components of Portland cement, form a Because of this high figure, the following work gelatinous calcium silicate hydrate (C-S-H gel). program was employed to check casing integrity; This gel is responsible for the strength and solid • pressure testing of the wellhead seals; • stability of the set cement at ordinary obtaining samples of annuli gas, liquid and temperatures. At well temperatures of less than well scrapings for corrosion activity 446oF the C-S-H gel is a very good binding investigations; and material: it is the first product to be formed from • topping up the casing annuli and pressure the hydration process. At higher temperatures the testing the production casing. C-S-H gel is subjected to metamorphism, which decreases the compressive strength of the cement Such activity meant that some wells were and increases the permeability of the cement once scheduled for workovers. Workovers were it sets. conducted to stop the substantial communication between the surface casing annulus and the At the high temperatures the C-S-H gel converts production casing annulus. Many wells provided to an alpha dicalcium silicate hydrate (α−C2SH). inconclusive information as to the need for a This is highly crystalline and is much more dense workover and were therefore placed into a than the C-S-H gel. Because of this, the shrinkage separate category. Several wells required further that occurs adversely affects the integrity of the observation. One such well, Della 15, was a poor cement. producer: abandonment of the well was required to recover the casing and tubing for examination. The major concern is not whether the strength of the cement is sufficient to support the casing but External corrosion of the surface casing by whether a high permeability will be created as a groundwater was thought to be the most likely result of these curing conditions. In order to cause for the Della 1 failure. Recovered casing prevent interzonal communication, the water from Della 15 indicated that corrosion of the permeability of well cements should be no more surface casing was from the inside and that the than 0.1 md. Nelson (1990) found that within one attack on the production casing was much more month of curing time, the water permeability of severe than that on the surface casing. This helped normal density class G systems was 10 to 100 to indicate that the source of the problem was due times higher than the recommended limit. The to the surface casing/production casing annular compressive strength and permeability changes of space. These wells suffered externally corroded neat Portland cement as a function of time is and parted production casing and some internal shown in Figure 11. corrosion of the opposing sections of the surface casing. The attacks appeared to be more intense across the parted region. However, none of the corrosion logs indicated holes in the surface casings. No significant cement bond was present behind the surface casing in the top 100 m of these wells.
25 Figure 11 Compressive strength and permeability behaviour of neat Portland cement at 446oF. Plots 1 and 2 represent normal density class G cement. Plot 3 represents class H cement and plot 4 indicates cement of lower density. Furthermore, the permeability of the high density class H system was barely acceptable (Nelson, 1990)
Figure 12 The accumulation of debris in well 14, SW Pannonian Basin in Croatia (Krilov and Loncaric, 2000)
26 Case history This type of microannulus is known as an inner The most severe case of permeability problems is microannulus. An outer microannulus is formed seen in well 14 at the gas condensate field in the when there is cement bulk shrinkage. This is a SW Pannonian Basin in Croatia (Fig. 12). worst-case scenario but a realistic one. A clear Analysis of the well cuttings showed that it understanding of these mechanisms is essential in consisted of high bottom-hole temperatures order to identify extreme cementing problems in (356oF at 3350 m) combined with sour gas and some cases. high salinity brine as formation fluids had the ability to cause significant problems in the well. The use of expanding cements can help to prevent the formation of microannulus. Theoretically, In 1988 a break in production was encountered. expanding cement will fill any gap and will At this point after a steady decrease in the ensure that good bonding is achieved between production period the hydrocarbon content in a either the casing and the cement or the cement one-month period dropped drastically (gas from and the formation. Expanding cement is known to 250 000 m3/day to 100 000 m3/day; condensate move only in the direction of the formation and from 20 m3/day to 10 m3/day). A sharp increase in not in the direction of the casing. water production was noted too. Approaching the end of 1993 the wellhead pressure dropped from Mechanism of shrinkage and 180 bar to 70 bar. The well was subsequently shut expansion in. Log analysis data indicated that a formation of The primary mechanism behind the phenomena of debris was present below the packer. Only 5 m of shrinkage and expansion has to do with the the 25 m of the perforated zone was left formation of hydration products. These products uncovered as a result of this debris. have different volumes compared with the hydrating components. Changes in external The debris could have resulted from: cement sample dimensions are referred to as bulk • long-term exposure in a harsh downhole shrinkage and bulk expansion. environment causing cement deterioration and opening the path for drastic water Cement chemical shrinkage breakthrough after a loss in zonal isolation; Cement chemical shrinkage is the basic and mechanism operating during the hydration of • more intensive sour brine breakthrough Portland cement. As the volumes of the water and causing a more aggressive cement corrosion cement are larger than the volume of the process resulting in the deterioration. hydration products, a volume contraction occurs. Measurement of total chemical shrinkage is Debris recovered from the well were shown to be conducted by placing cement slurry in a reservoir deteriorated cement, mixed with corrosion under free water access. The amount of water that products and downhole scale fragments. It was the cement adsorbs during hydration corresponds concluded that these constituents were the result to the total chemical shrinkage. of a 15-year exposure to aggressive downhole environments (sour gas brine). Experimental results have shown that the magnitude of the bulk shrinkage depends on the Microannular formation in cements environment in which the cement exists. Free It is possible that a microannulus can be formed access to additional water might make up for the between either the casing and the cement or the bulk shrinkage and a visible change in the volume cement and the formation. Such occurrences can will not be observed. But the absence of free be determined through the use of a cement bond water and pressure application makes excessive log response or through the observation of gas shrinkage possible. Chemical shrinkage is a linear migration problems. function of the percentage of the four major clinker minerals. This shrinkage is therefore One example of microannulus formation is given dependent on cement class. The water-cement in terms of the radial displacement of the casing ratio influences the magnitude and the rate of the resulting from wellbore temperature and/or chemical shrinkage. The shrinkage rate rises also pressure changes. This occurs predominantly with an increase in the curing temperature. when the wellbore pressure is decreased, ie. a change in mud weight when the cement has set.
27 Cement expansion action of the slow-moving gas at high pressure Cement expansion is an increase in bulk volume behind the casing wall. Many different aspects of the initial cement volume. This can be achieved must be considered when dealing with this as by the addition of cement expanding agents to the many factors can contribute to the long-term Portland cement. Cement expansion of cement is breakdown of the cement design. related to the chemical and mineralogical changes which result from the hydration and These further considerations consist of: recrystalisation of the expanding agents calcium • workability; sulphate, calcium sulphate hemihydrate or sodium • density; sulphate. The magnitude of the expansion is • set retardation; dependent on the amount of expanding agent • mud cake removal; added, the cement powder, the slurry design and • entrainment of formation gas; the curing conditions. Although expansion occurs, • shale sloughing; an overall total chemical shrinkage is still • pumping rate; and maintained. • mix consistency.
The general basis for using an expanding cement The consequences of cement shrinkage are only has to do with microannulus prevention. A likely to be realised over time. In North America problem arises if the properties of the cement are where tens of thousands of wells are either not adequately controlled. A cement may possess inactive or abandoned, some wells are leaking gas expansion properties that could damage the to the surface. This is a result of cement formation through excessive expansion. shrinkage and microannular formation. Unconsolidated formations limit the use of expanding cements in terms of inner annulus Some of the migrating gas can enter shallow formation. aquifers where traces of sulphurous compounds can sour the water making it non-potable. Baumgarte et al. (1999) reported that an Furthermore, it can cause the presence of expanding cement in a soft formation may be at corrosive waters that can deteriorate the cement risk of creating an inner annulus. This would and the casing. Escaping gas can cause further occur as the expansion moves radially outwards in trouble by entering household systems and the direction of the path of least resistance. flowing when the taps are turned on or by Because of this observation, expanding cement entering agricultural wells and locking the well. systems tend to work best in hard formations This gas influx is likely to increase the which can accept the expanding force of the concentration of gas over time. The extent to cement. The hard formations can pre-stress the which this is a problem needs to be determined. cement and thus build a good hydraulic seal. The cement only begins to expand after the cement It is the view of Dusseault (2000), that if these has set. It is therefore important to realise that the events are occurring then the standards for oil- bond between the formation and the cement and well cementing and abandonment are either not the casing and the cement will only improve with well founded or are based on a flawed system. time. When the problem to be rectified has been established, practices can be based on correct Long-term leaking of oil wells physical mechanisms which might give a better Oil and gas wells can develop leaks well after the chance of success. borehole has been abandoned. Several mechanisms are believed to be the cause of such Mud cake removal for cementing job leaks: Poor mud cake removal is another area of cement • channelling; failure. In order to cement successfully, a • poor mud cake removal; complete displacement of the drilling mud during • shrinkage; and the placement of the cement must be achieved. • high cement permeability. Many methods of mud removal exist, including: • pre-flushes; These leaks are instigated by cement shrinkage • centralisers; which in turn gives rise to the propagation of • casing movement; and fractures. These fractures propagate from the • conditioning of the drilling mud.
28 These procedures displace the mobile mud but The following observations were made as a result really need to be applied vigorously in order to of the experiment: remove some of the gelled mud. There is some • cement placement did not alter the fluid loss difficulty in removing the mudcake completely as substantially, indicating that the mud cake shown in laboratory testing (Haberman et al., was not removed or even altered by the 1991). Even when it is partially removed by the cementing process; tangential flow of fluids the filtration rate is not • in the absence of gelation effects, fluid-loss changed. An increase in filtration rate can be control additives in the cement slurries had no achieved by using mechanical scratchers or using affect on the fluid loss after cementing – fluid turbulent spacers at high displacement rates. loss was controlled by the filtration properties of the mud cake; An interesting point to investigate is the strength • the significant reduction in fluid loss caused a of the mud cake during the cementing process. Is large reduction in the overbalance pressure; low permeability enough to control the fluid loss • downhole fluid loss can be determined from cement slurries or do the filtration properties accurately by measurements made at the of the cement slurry dictate the overall fluid loss? surface; and An experiment by Haberman et al. (1991) • the magnitudes of downhole fluid losses were determined the function of pressure using a equivalent to a low-temperature, low-pressure regular HTHP mud fluid-loss cell at constant o API drilling mud fluid loss of approximately temperature (175 F). Haberman et al. found that 1 cc/30 min. when normalised to the same the filtration rate was independent for the surface area as the API test. overbalance pressure as expected for a dispersed, compressible mud cake. During each test the fluid The experiment provided an insight to the long loss was assumed to be approximately constant debate about whether fluid losses were dominated over the short time intervals used. by mud filter cake or cement filtration properties. It was found that in an overbalance situation Haberman et al. were unable to supply any (most common) the integrity of the mud cake is evidence as to the mud cake being removed quite high. Thus it indicated that mud cake was mechanically during cementing. This supported not removed by the cementing process. This the laboratory evidence which suggested the experiment did not involve the use of scratchers: strong mechanical nature of the filter cake. The it is recommended that the effectiveness of filter cake was held tightly onto the wellbore by scratchers to remove mud cake build up be the overbalance pressure. This test was conducted investigated. The use of scratchers for increasing under conditions present in the Mississippi River the effectiveness of the primary cementing job Delta. Therefore the conclusions from this should be investigated also. It is likely that experiment only apply to wells drilled in this scratchers will improve cementing practices region. It is difficult to predict whether similar because they provide a mechanical means for mud results could be expected in fields such as those in cake removal. Perhaps the poor mud removal the Cooper and Eromanga Basins. The properties in some wells could be the reason for experimental conditions in the Mississippi region poor primary cementing. Brumby 9 is one well were: with poor cementing properties: it is discussed • extensive sand intervals, commonly with later in this report. Pre-flushes are not used before permeability's greater than 100 md; cementing in the Cooper and Eromanga Basins. • typical (TVD) was in the vicinity of 10 000 ft Instead, two well volumes are circulated in order and the casing was cemented up to a depth of to remove the mud filter cake. The effectiveness approximately 5000 ft; of this technique is not known. • the bottom hole circulating temperature was o measured to be about 160 F; REMEDIAL CEMENTING • no scratchers were used; In many cases the primary cementing job fails and • centralisers were used across production there is a need for a remedial cementing job to be zones; and performed in order to achieve the design • casing was reciprocated. requirements of the primary cement job (Fig. 13). Many remedial jobs involve the technique of squeeze cementing or cement plugs. Marca (1990) noted the purpose of the remedial cementing as:
29 • repairing a primary cement job that failed due • cross-flow between formations which are at to the cement by-passing the mud or an different pressures; and insufficient cement height in the annulus; • potential contamination of freshwater • eliminating water intrusion; aquifers. • repairing casing leaks caused by corroded or split pipe; These problems can impact on the environment. • sealing off lost-circulation zones; Other impacts such as those affecting the • attempting to stop fluid migration into a production potential of the well are outside the producing zone; scope of this report. • abandoning a non-productive or depleted zone; One of the most difficult tasks in performing a • decreasing the producing gas–oil ratio by remedial procedure is determining where to isolating the gas zones from adjacent oil perform the perforations. Once this has been intervals; and established, correct circulation of the cement will • plugging all or part of a zone in a multizone help to provide a better remedial job. Figure 15 injection well so as to direct the injection into depicts the downhole circulation of cement after the desired intervals. the location of perforations.
The cement slurry in a remedial job is subject to a Typically, two situations exist behind the casing: • differential pressure against a filter of permeable the mud channel to be repaired is against a rock. The physical considerations that must be permeable formation and during the squeeze acknowledged relate to filtration, deposition of job the cement filter cake builds so that over filter cake and potential fracturing of formations. time it fills the void; and The differential pressure exerted on the slurry • circulation is established between two sets of causes the cement to lose part of its water to the perforations and a ‘circulation’ or ‘channel’ formation. As a result the slurry begins to squeeze is performed to replace the mud in dehydrate and a cake of partially dehydrated the channel with cement. cement is formed. The rate of filter cake formation (Fig. 14) is a result of four factors: In order for these operations to be succeed it is • formation permeability; necessary to maintain downhole pressure below • magnitude of differential pressure applied; the formation fracturing pressure. If a fracture • capacity of the slurry to lose fluid at was to occur then the ensuing path of least downhole conditions; and resistance would lead to large amounts of cement slurry being lost. This could not only damage the • time. formation but could also contaminate hydrocarbon zones and/or fresh aquifers. It is important to tailor the cement slurry to suit particular formation characteristics. For example, The issue of damaging zones of commercial a cement slurry with high water-loss capabilities interest is not an environmental one. What is of is likely to choke the wellbore with filter cake. concern is the possible reservoir damage that The design of the cement slurry should depend could lead to a loss in natural reservoir drive not upon formation characteristics. Ideally, the only in the local field but also neighbouring squeeze cement slurry needs to be constructed to fields. Damage that could deplete the reservoir control filter cake growth and allow uniform filter pressure of neighbouring in fields is a cause for cake to build up over all permeable surfaces. concern.
Applications of the squeeze cement In many cases it is not possible to perform a job remedial operation: the integrity of the wellbore One of the major reasons for a failed primary may not be strong enough to support such a job. cementing job is poor mud displacement, which Fracturing which could damage the formation causes the cement slurry to channel through the may then occur. It is not always true that in order drilling mud. Consequently, voids and pockets or to achieve a good squeeze job a high pressure channels are left behind the casing, resulting in gradient is needed. A high pressure is likely to insufficient hydraulic isolation between the exceed the fracture gradient of the formation and various permeable zones. If this condition is left lead to lost control of cement placement and uncorrected more problems are likely to arise:
30 Figure 13 Defective primary cementing job (Marca, 1990)
Figure 14 The mechanisms for cement cake build up in borehole (Baret et al., 1990)
31 Figure 15 Circulation of cement in squeeze cementing (Marca, 1990) formation invasion. A fracture has the ability to The use of lost circulation material is common extend across various zones and open unwanted also in the setting of plugs. It prevents the loss of channels of communication between previously excessive amounts of fluid to the formation isolated zones. Careful monitoring of the (Fig. 17). hydrostatic pressure can ensure that such damage does not arise. Reasons for cement plug failure The basis for determining the success of a One misconception that exists concerning the plugging is the depth of the top of the cement cement slurry is that it penetrates the pores of the plug and the hardness of the cement. These are rock. If this was to occur the permeability of the tested by cement bond logs and cement evaluation rock would need to be in excess of 100 darcies tools (CET) and also by radioactive tracers. Mud (Marca, 1990)! The only way that the cement contamination is a major cause of cement plug slurry can actually enter the formation is through failure as it affects the compressive strength of fractures or vughs. Only the mix water and the the cement significantly. dissolved substances in the cement slurry can enter the formation. The solids in the cement form Successful plugging involves the placement of the a filter cake on the face of the formation (Fig. 14). cement: the chances of success are greater when the plug is set in wellbores of near gauge. Cement plugs Furthermore, plugs have a better chance of Another procedure used for controlling lost meeting their design properties if they are set in circulation areas and attempting to repair a hard rock formations. Plugs set in soft formations damaged cementing job involves the plugging of are not likely to bond strongly with the formation the formation with a cement plug. Plugs are used because insufficient resistance may prevent a to sidetrack a fish, initiate directional drilling, good cement filter cake from forming. plug back a zone or a well, solve lost circulation or provide an anchor for openhole tests. They are also the main means for providing zonal isolation to wells that are to be abandoned (Fig. 16).
32 Figure 16 The use of cement plugs for zonal isolation in the abandonment of a well (Marca, 1990)
Figure 17 The use of a cement plug to prevent fluid loss to a thief zone (Marca, 1990)
33 Three principal means of plug failure have been • provide adequate zonal isolation; identified as of for concern: • protect sensitive areas such a freshwater aquifers; Mud contamination • provide good cement bonds between the This is a major cause of cement plug failure, as casing and cement and between the formation well as of cement failure in general. Mud and cement; contamination affects compressive strength. It • support loading of casing sufficiently; and generally results from a poorly centralised pipe. If • protect the casing against corrosion by tubing or drillpipe is not central in the hole it will preventing cross-flow of fluids behind the rest against the side of the well and slurry coming casing. out of the bottom will follow a path of least resistance. This causes cement channels in the With the design purpose stated, it is possible to mud and cement mixes with the mud when the perform tests to determine how well the cement is pipe is pulled out of the hole. performing. The evaluation of the procedure needs to be made after the job has been completed Insufficient cement volume so that the level of attaining the objectives can be If a plug is set in a poorly constructed part of a determined. Several techniques can be used to hole that may contain a washout it is likely that assess the integrity of cement behind the casing. inadequate amounts of cement would be in place. A guide for assessing the quality of cement jobs This means that the top of the cement column (incorporating the results of some techniques would not have reached the required height. In discussed in this report) is in Appendix 5. large sections mud displacement is difficult and therefore the chances of contaminating the cement Hydraulic testing slurry are increased. The plug should be placed in the most well-calibrated part of the hole. To Hydraulic testing of the degree of zonal isolation increase the chances of success Bradford and provided by the cement is a commonly done by Dees (1982) and Spradlin (1982) recommended a either dry or pressure testing. Zonal isolation is minimum of 500 ft (152 m) for plug height. Smith intended to prevent cross-flow behind the casing et al. (1983) recommended that a plug should be and helps to prevent the corrosion of the casing between 300 and 900 ft. Bradford and Dees by preventing formations penetrated in the argued that the extra cement is economical, wellbore from communicating. particularly when examining the cost of repeating the job, waiting on cement and retesting the plug. Pressure testing is typically performed after every surface or intermediate casing cement job after Water loss drilling the casing shoe. The pressure inside the casing is increased until the pressure exerted at Water loss considerations are essential when the casing shoe becomes greater than the pressure determining the placement characteristics of expected to be applied. A casing shoe that does cement. If filtrate invades a formation then not pressure up indicates a poor cement job, and a formation damage is likely to occur. Water loss remedial job is required to correct this. can prevent the complete hydration of the slurry which typically leads to weak cement. Dry testing (also known as a drill stem test Furthermore it leads to poor cement-formation [DST]) is a good tool for determining the bonds. For a drilling operator it is extremely effectiveness of a squeeze job or cement seal at important to be able to calculate and control the the top of a liner (Jutten & Morriss, 1990). This water loss. test aims to show that upon a reduction of casing pressure the formation fluids do not invade the TESTING THE QUALITY OF wellbore. A successful cementing job will show CEMENT JOBS no downhole pressure change during the opening A clear understanding of the design purpose of of the downhole valve or during the following the cement is needed if accurate means of cement shut-in period. Figure 18 shows the results job evaluations are to be employed. Otherwise it expected from a test performed before cement is impossible to determine whether the cementing squeezing and the result from a good DST run. job has fulfilled its requirements. A good cement job needs to:
34 Temperature logging acoustic log is related to the acoustic properties of Temperature surveys are useful in detecting the surrounding environment. As a result it is cement in the annulus several hours after cement possible to determine the quality of the acoustic placement (Jutten & Morriss, 1990). The reason coupling between the casing, cement and for this is the exothermic nature of cement formation. Good acoustic coupling indicates a hydration. The heat generated during the curing of good bond. But it does not necessarily mean that the cement raises the temperature of the wellbore adequate zonal isolation has been achieved. The which in turn induces a deviation from the normal lack of a reliable relationship between the temperature gradient (Fig. 19). The kinetics of acoustic coupling and hydraulic isolation is a cement hydration will be affected by the major limitation on this technique. However, it circulation of fluids prior to and during can give a general idea of wellbore conditions cementing. Thus the longer the circulation, the when the acoustic properties of the cement and lower the temperature. This results in longer formation are known. thickening times and smaller heat increases in the well. Temperature logs may not be all that According to Jutten and Morriss (1990), fairly suitable for evaluating the cement job in deep reliable data is obtained from the acoustic log wells because of the large temperature differences when there is: • between the top and the bottom of the well. good quality control procedure of the field Temperature increases are typically larger in a log; • bigger annulus because the amount of heat knowledge of the well and casing data; generated is proportional to the volume of • a good estimate of the relevant cement cement. properties; and • a clear understanding of the previous well Communication tester history cases. If channelling behind the casing is expected, the temperature logs can be effective tools in Cement bond log identifying the problem. Figure 20 shows a For the purposes of controlling fluid migration it typical case where flow behind the casing is is important that an effective bond between the occurring. This is the first temperature survey cement and the formation and between the cement prior to the injection of 80 bbl of diesel oil. The and the casing be achieved. One way to monitor second temperature survey, run only a short time this bond is through a cement bond log (CBL). after injection, shows a large temperature When used originally the amplitude of the decrease above the perforations and temperature acoustic signal in a firmly cemented pipe was variations down to the oil-water contact. Also, only a fraction of that of a free pipe. From their these variations indicate communication behind first use it was immediately established that a the casing. In such cases, remedial cementing CBL is the primary technology in cement must be performed to seal the annulus and reduce integrity monitoring (Fig. 21). A CBL has the the water content. ability not only to determine the bond between the cement and the casing but also between the Noise logging cement and the formation. The accuracy of a CBL is sufficient for determining the compressive Noise logging is a means of detecting whether strength of cement under favourable conditions. flow is occurring behind the casing (Jutten and Morriss, 1990). This tool works on the premise Many factors can affect the amplitude that flowing gas, water or oil produces noise. It measurement of the CBL (calibration of tool, can give an indication not only to what is flowing pressure, temperature etc.). So it is necessary to behind the casing but also of the magnitude of the speak of attenuation rates. The basic premise is problem. The tool relies on a succession of static that the attenuation rate helps to quantify the noise measurements and so it is difficult to results as a function of cement. perform when the tool is moving. Therefore it has little use in the oil and gas industry. Attenuation rates are linearly related to the percentage of the circumference of the casing Acoustic logging bonded by the cement. The concept of bond index Acoustic logging is a very popular means of (BI) was derived by Pardue et al. (1963). The cement evaluation in the oil and gas industry validity of a BI was confirmed by Jutten and (Jutten and Morriss, 1990). The response from the 35 Figure 18 Dry test expectations and results (Marca , 1990)
Figure 19 Typical temperature survey showing the probable cement top (Jutten and Morriss, 1990)
36 Figure 20 Temperature composite profile log before cement squeeze (Jutten and Morriss, 1990)
37 Figure 21 The configuration of a normal CBL tool run in the hole (Jutten and Morriss, 1990)
Figure 22 CBL interpretation chart (Jutten and Morriss, 1990)
38 Parcevaux (1987) for the percentage of cemented Cement evaluation tool area, regardless of the shape and fluid of the non- A CET has been utilised to overcome the CBL cemented area. limitations (Ataya et al., 1987). This evaluation tool is intended to improve the ability to A CBL interpretation chart in, was constructed distinguish between good and bad cement bonds, from the attenuation rate variations as a function as well as to identify the channels behind the of the cement, casing size and thickness (Fig. 22). casing accurately. It presents a relationship between the CBL and the cement compressive strength. The chart was This section comprises the predictions of the CET modified for lightweight cements by Bruckdorfer and the communication results. The CET is useful et al. (1983). in determining whether primary or subsequent cementing operations are the reasons for Limitations of cement bond logs communication. Remedial operations such as Traditional cement bond logs are limited by the cement squeezing can be used to correct the fact that in cemented sections a high amplitude problem. Like the CBL, the CET is limited to can be the result of either channelling or detection of fast formation arrivals. The pulse microannulus formation (Sheives et al., 1986). echo tool (see below) is useful in areas of fast Sometimes it may be difficult to determine the formations. exact case. Good cementing jobs have competent shear and Detection of microannulus with cement hydraulic bonds between the formation and the bond logs casing. The majority of cement jobs support the Measuring of the CBL amplitude is a function of casing in the hole. It is the hydraulic bond that the shear coupling of the casing to the medium blocks the flow of fluid across a cemented behind the casing (Fig. 23). If cement is present interval and reduces the danger of casing behind the casing and there is sufficient bond to corrosion. Effective hydraulic bonding means that provide a good shear coupling, a reduction in the cement seals the formation as well as the casing. amplitude will be recorded. An amplitude of 40– The CET determines the degree of this bond. 50 dB for a 3–foot spacing can be expected, depending on the properties of the cement. The Typically, the CET is run in combination with the sensitivity of the CBL is such that even very small CBL to help provide a greater insight into the microannuli will indicate large amplitudes which cement condition. The CET is a high frequency is evidence of poor bonds. This would then ultrasonic device with eight focused transducers indicate the potential presence of poor hydraulic arranged in a helical pattern on the sonde. A ninth seals even though zonal isolation may still be transducer is aligned with the tool axis and is used present. An advantage with the (CET) is that to monitor the velocity of sound in the fluid. The small gaps (<0.004 in.) have a relatively transducers act as both transmitters and receivers, insignificant effect on the calculation of the bond. emitting an ultra-sonic pulse perpendicular to the With such small bonds it is likely that the cement casing wall and detecting the reflected wave. is still providing good hydraulic seals. Even Figure 24 depicts the sonic wave paths through though the microannulus may not appear to be a different medium in the wellbore. problem at the time of testing, its significance for future problems is not known. Acoustic properties of cement Log responses in a cased hole primarily depend Determination of a microannulus using a CBL can on the acoustic properties of the hardened cement. be done by comparing a pressured log with an While acoustic properties of rocks are known, unpressured log. At a stage in the depth of the there are difficulties in cement acoustic properties well the hydrostatic pressure will be sufficient to because the physical properties of cement change close the microannulus. This is noted by a with time. Thus the log responses also change decrease in the amplitude of the CBL log. with time. Also, cement is physically not the same Furthermore, CET logs have the ability to be along the entire casing string. This can produce a sensitive to gas-filled microannuli because the large difference in the log response on long acoustic impedance contrast between steel and air strings where a large temperature difference exists is very great. Due to this, the bond value drops between the bottom and top of the cement below the free pipe value and most of the gas (Sheives et al., 1986). exists behind the casing. 39 Figure 23 CBL energy transmission as a function of microannulus wavelength (Jutten and Morriss, 1990)
Figure 24 Sonic wave paths (Jutten and Morriss, 1990)
40 Channels formations that may contain fractures, have a low The pulse echo tool (PET) is useful for the fracture gradient, be highly permeable, or are detection of channels in cement. PETs have the vuggy or cavernous (Davies & Hartogl, 1981). advantage over the CBL in being able to isolate The cement column in the wellbore exerts a the channels and to give a better circumferential weight on the formation that is dependent on the resolution for the bond value. Instead the PET weight of the cement being used and the height of gives a low ‘average’ bond amplitude over a the cement column. In many cases the formation 3–foot interval (Sheives et al., 1986) may be too weak and thus the anticipated pressure exerted by the mud column may exceed the Fast formations fracture gradient of the formation. As a result, some of the weaker formations can fracture and CBLs are not favoured in fast formations because fail. Low-density cements have been developed they do not give accurate data relating to bond for use in these type of environments. Such formation. In fast formations the sound velocity cements are typically created by mixing of the formation is more than the casing sound conventional cement slurries with microspheres velocity and therefore the formation arrival or even gas. The lowest probable conventional signals can interfere with the normal CBL casing cement slurry density is 11.0 lb/gal. Anything arrivals. The PET only measures the cement– lower than this value will have a permeability that casing bond. This results in less interference from is too high and a compressive strength that is too the formation signals on the measurement. low for adequate zonal isolation. However, consideration must be given when the cement sheath is small and the acoustic Although hollow ceramic or glass spheres are impedance of the material behind the casing is used in ultra-low density cements, they require different to that of the cement. Reflections from special handling techniques. Also, rheological this boundary can interfere with the resonance cement properties must be maintained accurately window, thereby causing inaccurate bond to prevent the spheres from floating. In addition, measurements. the collapse pressure of these microspheres is about 7250 psi. This implies that only limited PREVENTATIVE TECHNIQUES depths can be used for such slurries, as the Prevention of gas migration collapse pressure may be exceeded. By reducing the critical zone it is possible to For these reasons foamed cements are often reduce the possibility of gas migration (Bannister preferred. They are less expensive and much et al., 1983). This can be achieved by: easier to design that microsphere systems. • preventing large amounts of water loss from Furthermore, it is possible to mix foamed cement the slurry to a permeable formation; at lower densities and yet maintain better • decreasing initial hydrostatic pressure exerted properties. Davies and Hartog (1981) noted that by the fluid column; foamed cements have the following advantages: • limiting/preventing the annular pressure drop • they can develop a relatively high density in a until sufficient interstitial cement bonding has short period of time; occurred to prevent gas flow; and • they can cause less damage to water-sensitive • mechanical or chemical modifications, near formations; the gas zone, helps the cement form an • they can reduce the chance of annular gas impermeable barrier against gas migration: flow; and • filter cake inhibition: formation of an • they allow cementing of thief zones. impermeable cement filter cake against the gas-bearing zone; and The addition of gas does not affect the cement • gas-induced inhibition: chemical placement properties. Also, the density can be modification of the cement slurry by varied easily by changes in the gas concentration. the incoming gas to form an Because the reduced chance of cement loss to impermeable barrier to additional gas potential producing zones, the prospect of flow. increased well productivity and adequate zonal isolation is a benefit. Use of foamed cement In some situations foamed cement can be a Nitrogen is the most commonly used gas in a solution for cement problems that are related to foamed cement. Along with a surfactant to act as 41 a foaming agent, chemicals are used to improve which are three phase systems with many changes foam stability. Foamed cements are characterised taking place at the interfaces. Foamed cement is by their ‘quality’ which is the ratio of the gas in constant evolution due to the reorganisation of volume to the total foam volume. Figure 25 shows the bubbles that may shrink, grow or coalesce. As the process for mixing and creating of foamed a result it is virtually impossible to produce two cements. Two extreme structural situations can samples with the same initial bubble-size arise depending on the quality of the cement distribution. being used. Foamed cements are compressible fluids and thus the quality of the cement will Cured cement has a cement matrix with a network change through the process of circulation. This of pore structures. With a sufficient quality, each occurs through severe pressure variations. gas bubble is adjacent to several other gas Expected values would see a 1000 psi pressure bubbles. Outside forces such as dehydration will decreasing when flowing down the casing where cause some interfaces to rupture; as a result the pressures may exceed 10 000 psi. The quality will adjacent bubbles will form a channel of two or again decrease as it flows up the other side of the more bubbles. Foam stability is of major annulus. Thickening time does not depend on the importance not only to the bonding properties of quality. the cement but also to the ability of the cement to perform the task it was designed for. Unstable It is possible to estimate the quality of the foamed structures result in a pore structure that is cement by taking into account the compressibility imperfect and interconnected. Typically this laws for nitrogen and its solubility in the base occurs during the setting of the cement and is slurry. Foamed cements made in field conditions caused by the rupture of unstable nitrogen which involve high pressure and high shear rates bubbles upon contact with other bubbles. This have been found to be more stable than those results in coalescence and larger gas pockets. A created in laboratory conditions. It has also been sponge-like structure is encountered that has shown that higher pressures promote the creation lower compressive strength, higher permeability of smaller bubbles (Kopp et al., 2000). and poor bonding properties.
Pressure is not the only parameter that is important when considering foamed cements,
Figure 25 Facilities for the generation of foamed cements (Rozieres, et al., 1990)
42 Foamed cement limitations Use of flexible cements Rozieres et al., (1990) imposed the following The lack of ductility from conventional cements boundary conditions on the design process of has been identified as a major reason for the foamed cement: failure of primary cement jobs (Faul et al., 2000). • fracture and pore pressure profile; Flexible cements have been used to prevent • permeability of the formation; cement sheath cracking. Using of cements with • density of the lead slurry; vulcanised rubber is very costly: foamed cements • safety factors; and are an alternative. Foamed cements exhibit • length of the foam column. improved ductility over conventional cements and have the ability to stay at least one magnitude The foamed slurry should be designed to have a more ductile than normal cements. This ductility permeability less than one-tenth than that of the enables the cement sheath to flex as the casing critical formations. In order to support the casing, expands, thereby helping to protect it from the compressive strength of the cement needs to cracking. Limits apply to the cement quality: be in excess of 100 psi (and even above 500 psi if above 35% the quality is too porous for zonal it is required by regulations). The slurry must also isolation and below 20% it becomes too brittle. be able to contain the pore pressure of the formation. Because of these limits, a lower limit As the pressure in the reservoir decreases, the is placed upon the foamed cement density. effective stress action on the reservoir sand However, it is the fracture gradient of the increases: the increased stress can cause large formations that determines the upper limit of the compaction strain. This strain can deform the foamed cement density. casing. Even if the casing is not breached it can prevent workovers and recompletions. Foamed The main advantage of foamed cement is that it cement is also chosen for primary cementing has ductile properties that allow it to deform as purposes because it exhibits excellent the casing is pressurised. Unlike conventional displacement properties and is especially useful cement it will not crack. Furthermore, foamed when there are concerns over reservoir cement can have very favourable tensile strengths compaction or salt-formation flow. and displacement properties. Thus it is very effective in zonal isolation as demonstrated in Comparison of foam and flexible wells drilled in Wyoming (Kopp et al., 2000). cements The tensile strength of foamed cement make these The cost of foamed cement is often higher than low-density cements excellent for zonal isolation that of conventional cement. However, improved in many operations. The low compressive strength zonal isolation practices means that considerable of the foamed cement does not increase the risk of cost savings could be made over the life of the fracture initiation and propagation during well. hydraulic-fracturing treatments. Increased wellbore pressure during casing pressure tests or Displacement properties of foamed fracture stimulation treatments are tensile in cement nature. The sheath’s ability to withstand these During pumping foamed cement has the ability to stresses is evaluated by the cement’s mechanical develop higher dynamic-flow shear stress than properties and tensile strength. The cements, normal cements. This increases the mud- compressive strength is of minimal importance displacement properties of the cement. Slurry (Deeg et al., 1999). density is determined by the gas content or quality and depends on the pump rate of the base slurry, Flexible cement is one of the most durable foamer, stabiliser rates and nitrogen rate. The cements that can be used (Fig. 26). Flexible volume of gas used to foam the cement decreases, cement has a much longer life than foamed allowing slurry pressure to remain almost cement. But the limiting factor in its use is the constant during the system’s transition period. major cost involved and so it is unlikely to be This helps to control gas migration and formation- adopted for regular use. Strong reasons are fluid influx, which limits migration channels in needed to justify using this cement. Vulcanised the set cement sheath. rubber cement can offer a longer life in sour/sweet well applications.
43 Foamed cement is a good system as demonstrated both mechanisms are highly likely to create a path in Wyoming where six wells were analysed of potential fluid conductivity. (Kopp et al., 2000). Two wells were cemented with conventional high-strength, non-nitrified Many mathematical models have been proposed cement across the formations. Tracer tags to account for cement properties that will prevent indicated poor zonal isolation and stimulation the loss of integrity (Le Roy-Delage et al., 2000). treatments caused communication between the In order to avoid mechanical damage, cements high and low pressure zones Foamed cement was with a ratio of a high tensile strength to Young’s used in the other four wells and this helped to modulus and a low Young’s modulus compared obtain good zonal isolation. Furthermore, the with that of the rock are the best cements in terms stimulation treatment remained in the zone, little of mechanical durability. However, these fracture growth occurred outside the target requirements are functions of the downhole formation and communication did not occur specific well environment (well geometry, casing between the high and low pressure zones. In the properties, rock mechanical properties and conditions present in Wyoming, foamed cement expected loading history). It is possible that proved to be beneficial for zonal isolation. No mechanical damage can be caused by: work has been done to establish the validity of • large increases in wellbore pressure (pressure using foamed cement in wells in the Cooper and testing, mud weight increase, perforating and Eromanga Basins. gas production); • increase in wellbore temperature (steam Durable zonal isolation (new cements) injection and geothermal production); and Downhole changes may cause sufficient stress to • formation loading (compaction and faulting). alter the cement sheath and remove the zonal isolation that was created upon primary Weaker formations generally result in poor cementing. Apart from chemical changes, cements because the environment is not likely to mechanical failure is the single biggest reason for support cement deformation. In cases of a failure of a cement job. Mechanical failure leads temperature increase, the thermal properties of to the formation of cracks while debonding leads steel, cement and rock need to be considered. to the creation of a microannulus. Regardless of Furthermore, mechanical damage can also be due whether the failure is mechanical or chemical to cement shrinkage. Therefore non-shrinking cements should be used.
Figure 26 Life of the cement sheath for the three primary types of cements used (Kopp et al., 2000)
44 Microannuli formed between the casing and the In some cases corrosion cannot be detected until cement are referred to as inner microannulus and the damage is done. This is disturbing because the those between the cement and the formation as casing is the last line of defence in the well outer microannulus. Detection of microannuli system. The type of corrosion under consideration involves the use of CBL. Prevention of is the oxidation of the iron metal. This does not microannular formation is limited simply to the mean that oxygen is present. However, it does use of non-shrink cements. Cements that expand refer to the loss of electrons by the metal to gain a upon hydration are often preferable in conditions positive charge. that can accept such a physical change. Fe – 2e <-> Fe2+ Research has shown that expanding cements actually expand towards the formation and not in When this reaction occurs the metal loses an atom the direction of the casing (Baumgarte et al., to the electrolyte and a void in the metal can 1999). This annulus experiment tried to determine occur. This decreases the inherent strength of the the behaviour of an expanding cement sheath and metal and thus presents serious problems to the whether or not it provided an acceptable approach integrity of the casing design. to microannular prevention. An intention also was to determine the optimal conditions for using such Corrosive agents cements. The experiment indicated that cased Corrosive components in a reservoir environment wells cemented with expanding cements in soft include hydrogen sulphide, carbon dioxide and formations (for example, unconsolidated organic or inorganic sulphide. Oxygen accelerates sandstones) were at significant risk of corrosion. It rarely exists in the wellbore experiencing debonding between the cement and environment but is introduced through injecting the casing string as the cement moved radially water, gas or fire floods and circulating drilling outwards in the direction of least resistance. The fluid. The use of acids for well stimulation can optimal condition when using expanding cements have an effect on corrosion. was in hard formations that could provide resistance to the expanding cement. The success Carbon dioxide of the cement bond in part has to do with the elastic properties of the cement sheath. CO2 not only has an affect on the well casing, but is also can cause leaching of the cement in the Downhole corrosion prevention wellbore. CO2 forms a corrosive environment when it reduces the pH of water to below 7.0. Part of successful well completion planning CO2 testing is difficult primarily because it must relates to the casing protection. If the failure of be measured at system conditions: CO2 may the cement is known or anticipated, techniques escape when the system temperature is raised or can be utilised to enhance the longevity of the the system pressure is reduced. casing. Metals in the wellbore corrode when they come into contact with corrosive gases in the Hydrogen sulphide presence of water. The primary means of control Difficulties arise in predicting corrosion through is to remove the contact that exists between the hydrogen sulphide because the iron sulphide gases and the metal. Further controls rely on produced by corrosion is insoluble at the normal metallurgy, the wellbore environment and pH level. This can form a film which protects the cathodic protection. In general these techniques metal. However, in the presence of CO the pH are used in combination or even to obtain the best 2 level is lowered and the increased solubility of possible type of protection. iron sulphide prevents the formation of the protective film. The presence of oxygen can As demonstrated, problems can occur if effective accelerate the corrosion by either an aeration cell corrosion prevention methods are not in place. being formed (the oxygen-free environment Uncontrolled corrosion can lead to the results in a pitting of corrosion) or carbon dioxide replacement of equipment, lost production time, may lower the pH sufficiently to make the ferric contamination of subsurface formations, blowouts hydroxide somewhat soluble and fresh metal and well abandonment due to casing leaks. In available for corrosion. Hydrogen sulphide can terms of the downhole environment the major react with dissolved oxygen to form free sulphur concern lies with the possible contamination of which is also corrosive. subsurface formations, particularly freshwater aquifers. 45 Prevention methods then the metal will corrode at those points thereby Once the corrosion problem is identified, it is defeating the purpose of the protective coating. possible to implement a prevention or treatment plan. Corrosion prevention plans should be in Cathodic protection place before a well is drilled. Well programs Corrosion can be avoided by electrically implemented without regard to corrosion control preventing the oxidation of iron. This is done by can make it a very costly matter should corrosion applying an electrical charge that actually forces set in. The existing means of corrosion prevention electrons on to the pipe. The current is supplied or treatment are outlined below. by a voltage source such as a transformer rectifier. The well casing acts as the cathode on Fluid mechanics the negative side and the positive side is a piece In wells handling highly corrosive gas at high of metal that helps to complete the circuit after velocity, care must be taken to ensure that grounding through earth. Sufficient amounts of turbulent effects are not created by sudden electrons supplied to the casing prevent corrosion. reductions in pipe diameter or flow direction. Platinum and graphite electrodes are Weeter (1982) showed that larger tubing strings recommended because they can last between 10 with low flow velocities may have less corrosion and 20 years if correct operational procedures are than a smaller sized tubing handling the same followed. Figure 27 shows a typical downhole amount of fluid. cathodic protection arrangement.
Fluid additives to prevent or inhibit Corrosion testing corrosion There are a several means of determining whether Inhibitors are often used to prevent the oxidation corrosion is taking place in the wellbore. of bare metal. Typically they tend to be oil- soluble organic chemicals that prevent water and Metal coupons corrosive compounds from reaching the bare A metal coupon is essentially a piece of metal that metal surface. is as close to the metal present in the wellbore as physically possible. This method has limitations: Removal of corrosive gases • it is not convenient to place these coupons Corrosive gases such as carbon dioxide, hydrogen downhole; and sulphide and oxygen present problems. But it is • coupons need to be placed in areas where the extremely expensive to remove these gases from water can be trapped so that readings are the wellbore. accurate.
Correct selection of materials for tubular Surface measurements are not indicative of the goods and fittings extent of corrosion at the bottom of the hole or of corrosion at any intermediate depth in the hole. Corrosion resistant materials should be used in all potentially corrosive environments. However, their use is governed by cost. It is often too Corrator probes expensive to justify their use. Furthermore, Corrator probes are used to monitor a continuous corrosion resistant materials may not provide the electrolyte. If connected to a recorder the probes correct mechanical properties required for the job. can provide a measure of the continuous For example, many stainless steel applications, corrosion rate for both general and pitting types of which are in fact corrosion resistant, often lack corrosion. However, they are limited in the same the physical strength as well as the malleability a way as the metal coupons: they can only monitor required. corrosion at the installation point.
Coatings Protective coatings may be applied in instances where it is not practical to use non-corrosive material. The coating can be an application of cement or various kinds of plastics to the inside of the tubing. It is difficult to apply the coating evenly to eliminate small gaps in the coating surface. If areas of the metal are left uncoated 46 Figure 27 Typical downhole arrangement of continuous corrosion inhibitor (Weeter, 1982)
CONCLUSION is at major risk. Furthermore, high temperatures The major concern for cement deterioration is help to intensify carbonic acid leaching which leaching which is a thermodynamically favoured affects cements in these conditions and increases reaction. Concern increases because additives are the rate of degradation. This will lead to cement not present to prevent or eliminate cement deterioration with a loss of compressive strength. carbonation in hostile environments. The rate at The conditions in the Cooper and Eromanga which the cement is worn away is not known. Basins may not be as severe as that expressed in This is an area for further study. Also, the the case history. However, with time it is likely formulation of a cement carbonation model in that cements exposed to even moderate conditions differing downhole environments needs further will deteriorate. It is important to understand that investigation. the risk of cement failure increases over time: once initiated the risk is most likely to grow The good bonds detected at the time of casing in exponentially. the case history had deteriorated substantially some 15 years later and had caused a plunge in Monitoring well integrity productivity. Cross-flow issues were also a An array of tools exists for the evaluation of a concern. There was a substantial loss of cement cement job. At this stage the CBL seems to be the integrity behind the 7 in. casing along the most accepted tool for the evaluation of zonal perforated interval. Log responses indicated poor isolation in the wellbore. Pulse echo logs have bonding or free pipe. This indication followed the also been considered. There seems to be some good bonds in the first stage of cementing. The success in their use with enhanced channel log indicates cement degradation and resolution, suitability in fast formations and deterioration and possible migration of crushed sensitivity to a gas-filled microannulus. While fragments from annuli to the wellbore, leaving such equipment may not be 100% accurate, it is free space behind the casing. However, the case satisfactory for providing evidence of the integrity history shows the need for continued cement of the cement job. monitoring and highlights the fact that cements are not a permanent solution. The most conclusive test for evaluating how effective a cementing program has been is time. The case history was one of the more extreme The effective evaluation of the cements used condition wells. Conditions in this well were should involve the study of already cemented favourable for cement deterioration. Cement in wells. wells exposed for long periods of time to formation brine saturated with sour gas (rich in o o CO2) under high temperatures (>180 C/ >356 F) 47 Cement time-scale consider filling the abandoned hole with shales The well in the case history started to fail 15 and clay similar to those originally encountered in years after the cement had been put in place. the wellbore. Such a technique will need Deterioration most probably occurred long before investigation. this time. So what timeframe for the isolation of a formation is required? This report does not Zones exist in some older wells that have address the timeframe for the life of cement but formations exposed directly to casing. This poses one possible outcome concerning cement life may problems, especially in cases where the cement be that the technology does not exist to be able to was the primary means for corrosion prevention. provide isolation timeframes. Absolute favourable The risk of corrosion increases if sufficient casing conditions would need to be present to ensure that protection is not offered. This was a case in Della cement integrity is maintained for an infinite time 1 where the casing was not cemented between 15 after well abandonment. This is never likely to and 90 m. Many older wells have received some occur since wellbore cement is exposed to treatment (cathodic protection) for corrosion. dynamic conditions and streams of potentially However, the adequacy of this practice needs corrosive compounds. investigation. It is possible that corrosion may have jeopardised the integrity of the casing to Della 1 indicated that the majority of older wells point where failure is imminent. lacked cement in areas near the surface and in other sections of the well. This allowed formation Further study needs to be conducted into the rates fluid direct communication with the casing string. of cement leaching. It is necessary to construct a The risk of external corrosion would be increased model that indicates the rate of cement leaching without sufficient means of corrosion prevention. that can be expected in given environments. One Modern-day cementing involves running cement expected outcome from the study would be to well into the surface casing which allows for provide a means for evaluating the degree of better protection of the casing from contact with a cement deterioration. This study should also formation. investigate the level of cement deterioration and provide a point at which the cement is likely to be Fluid loss prevented from fulfilling the zonal isolation requirements. Such a point will most likely The loss of fluid from the cement has never been represent a percentage weight reduction or a real concern. Only mix water and dissolved thickness loss at which the properties of the substances have the ability to enter the formation. cement are affected. Very large permeability's must exist in order for the cement to invade the formation. Furthermore, A study should be conducted into the validity of the cement slurry does not contain any the mud removal procedures. No pre-flushes are compounds of known toxicity and fluid losses are used in the Cooper and Eromanga Basins. Instead so small as to not constitute a need for concern. the two hole volumes are circulated. The use of scratchers for mud cake removal is minimal. Is RECOMMENDATIONS this procedure adequate in removing the mud cake Any disputable formation penetrated in the from the wellbore? Wells that encountered wellbore which is likely to be subject to problems with the cementing job should be contamination should be isolated until sufficient investigated to determine the effectiveness of the evidence can be obtained to confirm or negate this mud removal program. Practices such as pre- need. flushes and scratchers need further investigation. The practices may require changing or the Present cementing technology does not to provide rheology of the mud properties may need to be adequate zonal isolation for long periods. As a altered for more favourable removal. result, it is recommended that further work be conducted into the adequacy of cementing Examining the validity and cost effectiveness of practices. The research should include a model foamed and vulcanised rubber cements should be for predicting the relative time-scale for cement considered. A means for increasing cement life integrity in certain environments (for example, could reduce the costs involved in remediation corrosive and high temperature environments). work. A study should be made of this cement Consideration should be given to well technology to conditions specific to the Cooper abandonment practices. It may be viable to and Eromanga Basins. The use of foamed cements
48 is gaining interest, particularly in areas where the formation is known to be weak.
Continued cross-flow from poorly isolated wellbores is likely to provide a mechanism for the depletion of natural reservoir energy and is potentially a source of contamination of fresh water aquifers. Is there a stage where the pressure in the sands reaches an equilibrium and cross- flow ceases? Will the natural reservoir energy continuously be supplemented by gas cap or water drive mechanisms and thus enable cross-flow for an indefinite period of time? Answers to these questions will be useful in helping to address the problems associated with cross-flow.
Current cementing technology is not sufficient in providing an indefinite zonal isolation. New methods need to be considered, particularly when considering the abandonment of the well. These conclusions were some of the outcomes arising from this detailed investigation into the downhole environmental risks associated with drilling and completion practices in the Cooper and Eromanga Basins. By pursuing these lines of enquires, benefits may become apparent to the oil and gas industry.
49 APPENDIXES Appendix 1 Types of filtration STATIC FILTRATION The static filtration equation represents Darcy’s law of fluid flow. This is the same equation that is used where there is a pressure-induced flow of fluids through. In this case the mud cake is visualised as being a thin cylinder. dV ∆ f = kA P µ dt hmc where dVf /dt = filtration rate (cc/s) k = mud cake permeability (Darcies) A = flow area (cm2) µ = filtrate viscosity (cp) ∆P = pressure drop across the mud cake (atm) hmc = mud cake thickness (cm)
This is not a perfect model because it does not account for permeability, mud cake thickness and the filtration rate (which is not constant). The greatest variation in permeability occurs early in the filtration process where the only resistance to flow is caused by the filter paper. This means that there is a large initial permeability that decreases quickly as the mud cake develops and reaches a steady value when the mud cake has developed to the point where its growth is balanced by its erosion. This initial large permeability results in what is known as spurt loss.
To improve the model it is necessary to express the effect of changing filtration rates as the filtration proceeds. Considering a relationship between the volume filtered and the thickness of the filter cake does this. The volume of solids filtered from the mud is equal to the volume of solids in the mud cake: fsmVm= fschmcA where fsm = fraction of solids in the mud Vm = volume of mud that has been filtered fsc = fraction of solids in the mud cakes The volume of the mud that has been filtered is equal to the volume of the mud cake added to the volume of the filtrate: Vm = hmcA + Vf where Vf = volume of filtrate
Then rearrange the equation in terms of hmc. V h = f mc f A( sc −1) f sm
Then by using hmc in Darcy’s law and combining the equations the result will give:
f = ∆ sc − t V f 2k P( 1)A f sm A
This equation has the advantage because at a constant fraction of solids in the mud cake the volume of mud filtered through it can be determined. This means it is a useful way of determining the tendency of a drilling mud or cement mixture to lose water into a permeable formation. It is possible to determine the solid fraction in the mud cake by either drying the mud cake and measuring the density of the filtrate or assuming 50 that the filtrate has a zero solid fraction. It is then possible to rewrite the filtrate volume/time relationship in terms of t and constant c: = V f c t By using this equation it is possible to make a quick estimate of how much fluid will be lost when drilling though permeable formations. This equation is most useful, however, for determining the water loss properties of a drilling mud as well as the determining the spurt loss. The disadvantage of the equation is that it does not take into account pore plugging effects or formation permeability. Spurt loss is the volume intercept on a graph of filtration volume plotted against root time. Also, API water loss is defined as the volume filtered through an API filter press under 100 psig in 30 min. The square root relationship (as above) means that the API water loss and spurt loss is also equal to twice the volume flowing through an API filter press and a spurt loss of 7.5 min:
V30 –Vsp = 2(V7.5-Vsp).
Bit filtration Bit filtration, the first filtration type is due to the action of the drill bit. Very little filter cake forms on the bottom of the hole because the action of mud jets is highly erosive. In addition, the action of the bit is such that every time a bit tooth strikes, a fresh surface of rock is exposed. Beneath the bit filtration is restricted due to an internal filter cake that forms in the pores of the rock just ahead of the drill bit.
Dynamic filtration Under dynamic conditions the growth of the filter cake is limited by the erosive behaviour of the drilling fluid. When the rock is first exposed the rate of filtration is very high and the mud cake grows quickly. The rate of growth decreases with time until eventually the erosion rate equals the formation rate and the thickness of the mud cake remains constant. In dynamic conditions the rate of filtration depends on the thickness and permeability of the cake: these are governed by Darcy’s law. However, under static conditions the cake thickness increases to infinity (Fig. A1).
Figure A1 Relative static and dynamic filtration in the bore hole (Outmans, 1963)
51 The filtration rate for dynamic filtration is given by the following equation.
k (τ / f ) −ν +1 Q = 1 µδ (−ν +1) where k1= cake permeability τ = shear rate exerted by the mud stream f = coefficient of internal friction of cakes surface layer δ = thickness of the cake subject to erosion (-v+1) = is a function of the cake’s compressibility Q = dynamic filtration
Permeability varies the most early in the filtration when the only resistance to fluid flow is from the formation. The permeability is greatest initially and it decreases gradually as the mud cake develops on the filter paper. The permeability of the filter paper reaches a constant value when the mud cake has reached a relevant level. This effect is known as mud spurt.
Mud spurt occurs when the drilling mud comes into contact with the filter paper. The particles in the mud range from large to small. The smaller particles pass through the filter paper easily yet the larger particles become trapped in the pore spaces of the filter paper and in a sense block it up. Gradually the finer particles in the mud stick to the larger particles in the pore space and start to clog the pores. It should be noted that particles of a critical size are needed to initiate the clogging of the pores. If the particles are too big then they will not enter the pores. Particles that are too small will simply pass through the pores and not get stuck. Once the pore space has been completely clogged by the particles a bridge is formed and no more solids can pass through the pore, no matter how small they are. At this stage only filtrate can invade the formation. The mud spurt time is very much dependent on the size and amount of bridging particles present. A region of three zones is identified in the permeable formation (Fig. 1).
52 Appendix 2 Mud recap report data – Drilling fluid lost to the formation Depth (ft) Volume (bbl) Depth (ft) Volume (bbl) Moomba 98 994 67 Burke East 1 5406 34 2525 35 5970 89 3530 33 6386 149 6432 5 7375 183 6615 3 7946 187 6950 4 8331 91 7550 37 8627 78 7964 23 8698 17 8469 68 8698 150 8825 98 8698 30 8825 64 8698 34 8825 5 8698 2 8825 5 Total Fluid Loss (bbl) 1044 8825 6 Moomba 114 2470 261 8825 6 3020 27 8825 6 4270 10 8825 6 5500 10 8825 6 6487 34 8825 6 7136 111 8825 6 7348 108 8825 6 7847 79 8825 6 9047 129 8825 6 9047 18 8825 6 9047 26 Total Fluid Loss (bbl) 513 9047 15 Dullingari 50 591 60 Total Fluid Loss (bbl) 828 2484 150 Moomba 115 577 19 3016 78 3020 105 3016 56 3020 114 3026 0 4699 51 3681 62 5500 10 4280 66 6330 57 5141 65 7092 52 5734 30 7300 108 Total Fluid Loss (bbl) 567 7456 55 Brumby 9 1592 20 7991 20 Total Fluid Loss (bbl) 20 8640 93 Grenache 1 2188 48 8640 15 3522 150 Total Fluid Loss (bbl) 699 9726 29 Moomba 116 020 10014 60 1733 191 10082 17 1733 40 10329 20 1733 0 10738 40 3310 202 10738 80 5485 136 10738 70 6212 103 Total Fluid Loss (bbl) 514 6718 190 6946 106 7153 21 7513 75 7835 52 7835 115 7835 13 Total Fluid Loss (bbl) 1264
53 Depth (ft) Volume (bbl) Depth (ft) Volume (bbl) Moomba 118 811 36 Moomba 128 6465 46 1710 192 7145 86 1710 11 7460 0 1710 8 7988 113 3465 145 8670 17 5023 236 9069 185 5051 29 9069 0 5426 143 9069 0 5192 61 9069 0 6397 161 Total Fluid Loss (bbl) 447 6566 72 Moomba 134 6171 5 6771 76 6815 266 6858 125 7153 75 7070 57 7394 86 7201 50 7766 84 7481 86 8589 177 7824 63 8671 113 7824 70 8835 95 7824 30 9109 61 Total Fluid Loss (bbl) 1651 9110 134 Moomba 119 5849 92 9110 39 6416 95 9110 40 6850 129 9292 105 6946 67 9400 31 7462 130 9580 30 7588 16 9713 78 7588 24 9836 127 7588 27 9942 106 Total Fluid Loss (bbl) 580 10112 137 Moomba 125 5357 186 10202 35 6530 140 10434 39 7220 79 10507 76 7400 100 10507 40 7675 116 10507 8 8541 70 10507 48 9092 48 10507 0 Total Fluid Loss (bbl) 739 Total Fluid Loss (bbl) 2036 Moomba 126 6282 1 Miluna 21 1820 594 6919 2 1820 33 7092 0 Total Fluid Loss (bbl) 627 7236 0 7373 0 7442 0 8125 1 8275 4 8275 70 8634 36 8634 20 8634 0 Total Fluid Loss (bbl) 134
54 Appendix 3 Environmental objectives and assessment criteria Minimise loss This objective seeks to protect the Drilling and Completion Activities of reservoir water quality and water pressure of • Casing design (including setting depths) have been and aquifer aquifers that may potentially be useful carried out in accordance with company defined pressures and as water supplies, and to maintain procedures which satisfy worst case expected loads contamination pressure in sands that may host and environmental conditions determined for the of freshwater petroleum accumulations elsewhere. particular well. aquifers. • Casing set in accord with design parameters and To address this objective, the risks of company approved procedures. crossflow between formations known to • Sufficient isolation between any of the formations be permeable and in natural hydraulic listed in the adjacent column – where present – is isolation from each other, or where substantiated (eg through well logs, pressure there is insufficient information to measurements or casing integrity measurements). determine that they are permeable or in • hydraulic communication, must be For cases where isolation of these formations is not assessed on a case by case basis and established, sufficient evidence is available to procedures implemented to isolate demonstrate that they are in natural hydraulic these formations. communication.
The following geological formations in Producing Wells the Cooper-Eromanga Basins may • Monitoring programs, carried out in accord with contain permeable sands (aquifers) company approved procedure(s), demonstrate no which may be in natural hydraulic crossflow or fluid migration occurring behind casing. isolation from each other (from • Casing integrity and corrosion monitoring programs, shallowest to deepest): carried out in accordance with company approved • Eyre formation; procedure(s), show adequate casing condition to • Winton formation; satisfy the objective. • Mackunda formation; Inactive Wells • Coorikiana sandstone; • In the case where a well is suspended for a • Cadna-owie formation; prolonged period of time: • Namur sandstone; • Monitoring methods for detecting fluid migration, • Adori sandstone; carried out in accord with company approved • Hutton sandstone; procedures for this purpose, are in place and show • Poolowanna formation; no fluid migration. • Cuddapan formation; • Nappamerri Group formations, Well Abandonment Activities Walkandi and Peera Peera • Plugs set to isolate aquifers through the well bore, formations (multiple sands); designed and set in accord with defined procedures • Toolachee formation (multiple to satisfy worst case expected loads and downhole sands); environmental conditions. • • Daralingie formation (multiple Plugs have been set to isolate all aquifers which are sands); present which are not in natural hydraulic communication nor have been isolated by cement • Epsilon formation (multiple sands); behind casing. • Patchawarra, Mt Toodna or Purni formations (multiple sands); • Tirrawarra sandstone or Sturat Range formation; • Merrimelia Boorthanna and Crown Point formations (multiple sands); • Basement reservoirs.
55 Appendix 4 APPEA 1996 drilling fluids survey
56 57 58 59 60 Appendix 5 Goal attainment scaling for oil-well cements Goal attainment scaling for oil-well cements is proposed as method in which the downhole integrity of the wellbore can be investigated and evaluated. It is similar to the assessment concept used to assess the restoration of abandoned wellsites in the Cooper Basin.
A scale for assessing the cement can be used to grade the cement on the basis of how well it is fulfilling the task it was intended for. The grading of the cement will be based:
Score Outcome -2 Much less than expected -1 Less than expected 0 Expected
Objectives of the cement job In order to grade the level at which the cement is fulfilling its task, it is necessary to identify the purpose of a cementing job. The purpose of a cement job in the abandonment of the well is to provide: • zonal isolation for formations penetrated in the wellbore (zonal isolation is essential for formations that are not naturally in hydraulic communication; timeframe for such isolation needs to be provided on a case-by-case basis; • some structural support to the wellbore and help maintain the integrity of the formation; and • protection of the casing through formation fluids not coming into direct contact with the casing.
When the cementing job does not meet the lowest level that it was expected to reach, concerns arise as to its effectiveness in isolating the formations. In an environmental sense it is very important that the zones be isolated to prevent cross-flow and the potential contamination of freshwater aquifers.
The aim of this assessment is to grade the level at which the objectives of the well abandonment are achieved. For objectives that are not reached an outcome of at least 0 means appropriate corrective measures can be taken.
What constitutes a good cement job? The most important part of a cement job is the adequate isolation of zones penetrated in the wellbore. A good cement job isolates these areas by means of a valid hydraulic seal and provides protection from cross- flow. Furthermore, a good cement job fulfils the objectives of well abandonment. In order to achieve a quality cement job it is necessary for the cement to create a sufficient bond with the wall of the formation. The cement must also have a permeability low enough to inhibit migration and have sufficient properties to quench the formation of a microannulus. A good cement job should also have reached the required height in the wellbore and achieved a hardness that has the required shear strength to support the casing in the wellbore.
Evaluation of the cement job CBL and CET are the most common means of evaluating the quality of the cement job. These tools are used to determine the degree of contact between the formation and the cement. In part this determines the degree of zonal isolation present within the wellbore. The CBL provides a reasonable determination of the cement- to-formation bond. The CET provides a comprehensive determination of the cement-to-casing bond. These tools, when used in conjunction, are extremely good at determining the effectiveness of the cement bond. Another method for testing the effectiveness of the job is to use temperature sensitive logs. These are most commonly used to detect the cross-flow behind the casing.
In order to grade the quality of the cementing job it is recommended that an independent body carry out the tests. While PIRSA should be required to survey the data and impose a grade, cost incurred by this process should be borne by industry: it should form part of a competent well completion program.
61 What tests should be performed? In order to grade the cement system, a series of tests based on the same grading system should be concluded. In the event that a grade indicates that the job has been completed poorly, a remedial program should be submitted by the relevant operator. This program should address the problems identified by the independent body and how they are to be corrected. If a remedial program cannot be conducted due to a poor formation or other factors, another party should be contracted to assess the validity of the situation.
Tests should be conducted on those wells that have problems known to be associated with the cementing program or wells drilled into hostile environments. The tests could be implemented at the time of well abandonment and then at 5 and 10 year intervals. Follow-up tests could be conducted if a concern regarding the cement properties existed. However, cost considerations could make such an exercise prohibitive: testing over a long period remains the only method for determining the integrity of the cement but the cost would not make this a viable option.
The following tests should be performed:
Zonal isolation This test is conducted to evaluate the degree to which the cement is providing sufficient zonal isolation. Formation temperature testers should be used to detect the potential cross-flow of formation fluids behind the casing. The following scale provides a grading system:
Score Outcome -2 No zonal isolation due to a complete failure of the cement design. Little to no cement exists in areas that were marked for zonal isolation. Extremely poor cement job. Cement did not reach required height. -1 Zonal isolation is minimal. Failure of cement system with small amounts of cement existing in areas identified for zonal isolation. Poor cement program. 0 Zones identified for zonal isolation have been isolated. Cement program was of a satisfactory level. Cement reached expected height.
DST may be a another tool that can be implemented to test the quality of the cement seal. A successful cementing job will show no downhole pressure change during the opening of the downhole valve or during the following shut-in period. The expected dry test results are in Figure 18.
Cement bond The purpose of this test is to evaluate the degree of bonding present between the cement and the formation and between the cement and the casing. This is investigated by CETs and CBLs.
Score Outcome -2 No bonding between the cement/casing and cement/formation. Severe channels allowing the migration of fluids between formations. -1 Some bonding, but formations are still able to communicate hydraulically. Formation of microannulus has occurred. 0 Cement bond is sufficient to prevent cross flow. The bond achieved by the cement is satisfactory.
Cement durability Cement durability only has validity as a test for some time later in the well time-scale. It is acceptable to neglect the first test at the time of well abandonment as cement durability is really a measure of how well the cement is able to combat the downhole environment and ensure continued zonal isolation. It is expected that the score of the cement durability in a wellbore will decline as time proceeds. Action should be taken to correct the level of durability before it becomes unacceptable. The grading system could be applied here but the guidelines are difficult to impose.
62 Costs of programs The remedial programs and wellbore assessments are not only costly but also are time consuming. Testing each well is certainly not proposed. However, wells that have had problems at the time of completion, or are in an area known to accelerate the degradation of cement, need to be checked. It is recommended that this process be included in the operator’s abandonment program. The operator has a responsibility to prove that cementing procedures are meeting the requirements they were designed for. Goal attainment scaling for oil- well cements should be used in aging wells as a means of demonstrating the effectiveness of the well procedure in place.
63 Appendix 6 Mud program The function of the mud is to: • cool the bit and drill string to prolong bearing life and reduce pipe damage from the heat; • bring cuttings produced by the drill bit to the surface (a good mud will keep cuttings from sticking above the bits of the collars: it is important to maintain a clean hole); • suspend the cuttings when the pump is shut off so that the cuttings are prevented from falling down around the bit and collars; • build a mud cake in the bore so that the borehole is prevented from caving in and losing drilling fluid; • reduce formation invasion and improve electric logging conditions for formations; and • control downhole pressures through the weight of the mud column.
In the field barite is used to provide weight to the mud: this helps to control any pressure kicks. Gels are used to help build viscosity in the mud. They help form mud cakes in the borehole as well as suspending cuttings in the mud system. A good mud cake must prevent the mud flowing into the formation. Adding lost circulation material (mica, cellophane flakes and plastic) can do this. It is important that in zones of lost circulation the drilling mud is monitored continually in order to prevent any loss of mud that could lead to a blowout.
There are five main types of mud: freshwater, saltwater, oil-based, surfactant and emulsion. The best mud for drilling the formation needs to be chosen. This is done by evaluating the formation in which the drilling is going to take place. The mud is required to have turbulent flow in the wellbore as opposed to laminar flow. Turbulent flow enables the cuttings to come to the surface flat rather that tumbling up the annulus. It also helps to increase the annular velocity and aids in cleaning the wellbore.
In petroleum engineering the characteristics of the drilling fluid are essential because they not only help to control penetration rates and extend the life of the bit but they also help to prevent any pressure kicks caused by any unexpected drilling regions. The following properties must be known in order to form a reliable drilling mud.
Viscosity of the drilling fluid The resistance to flow of a drilling fluid depends on friction between: • solids; • solid and liquid phases; • liquid phases; and • the particles of the drilling fluid.
The first component that affects resistance to flow is known as viscosity. This is caused by the solid clay particles in the mud rubbing together (mechanical friction). There are two types of viscosity: effective and plastic. The second component that affects resistance to flow is known as the yield strength. This is caused by the intermolecular attraction that exists between the clay molecules which tend to bind together to form structures. This tendency depends upon: • the surface properties of the mud; • the concentration of the solids in the mud; and • the electrochemical environment of the solids in solution.
Another important property of the mud is the gel strength. This is the minimum energy required to start the mud to flow (setting properties).
Components used in drilling fluids Many clays and additives can be used to create a drilling mud. The major components used are bentonite and barite.
64 Bentonite Bentonite is used not only because it is cheap and readily available, but it also: • increases the hole cleaning ability; • it reduces the water seepage or the filtration into formations that are permeable; • it forms thin mud cakes that have low permeability; • it help to keep the hole stable when the cementing is poor; and • it helps to avoid, and in some instances to overcome, the loss of circulation.
Barite The main purpose of barite in a drilling fluid is to increase the density of the mud. Barite has a high specific gravity and because it is not soluble in water it does not react with other components in the mud.
65 Appendix 7 Effect of temperature on the rheology of drilling fluids The rheological properties of drilling mud under downhole conditions may be very different from those measurements made at ambient pressures and temperatures. Temperatures in downhole conditions depend on the geothermal gradient. Elevated temperatures can influence the rheological properties of drilling fluids in any of the following ways: • physically – an increase in temperature decreases the viscosity of the liquid phase; • chemically – all hydroxides react with clay minerals at temperatures above 200oF (and temperature does not disturb low alkalinity mud but high alkalinity mud can react at temperatures above 200oF); and • electrochemically – an increase in temperature increases the ionic activity of any electrolyte and the solubility of any partially soluble salt that may be present in the mud.
Flocculation A mud consists of many colloid particles that have the ability to remain indefinitely in suspension because of their extremely small size. In pure water they cannot agglomerate (form a mass) because of the interference between the highly diffuse double layers. But if an electrolyte is added, in this case salt, then the particles can approach each other so closely that the attractive forces predominate and the particles can thus agglomerate. This phenomenon is known as flocculation. If the concentration of clay in suspension is high enough, flocculation can cause the formation of a continuous gel structure. The gels commonly observed in aqueous drilling fluids are the result of flocculation by soluble salts.
Temperature effect on water loss An increase in temperature could also work to decrease the plastic viscosity by decreasing the amount of free water bound to the clay and polymer particles. This effect can only occur at temperatures that are high enough to break the bond between the particles.
66 Appendix 8 Effect of cement additives Cement slurry has poor fluid retention properties and can lose a significant amount of water to a formation rapidly. Cement additives provide protection against water loss and help to control other properties of the mud. They also: • vary cement density; • increase or decrease cement strength; • accelerate or retard setting time; • control filtration rate; • reduce or increase slurry viscosity; • provide bridge for lost circulation control; and • improve the economics of production.
Cement density In some cases long cement columns may be constructed without risking formation breakdown. Typically there are three methods that can be used in order to decrease the density of the cement slurry. The first involves adding lightweight materials such as bentonite and attapulgite, which permit an increased mix with water and at the same time prevent the separation of water. Secondly, it may be possible to add hollow ceramic spheres that have a low specific gravity which can provide reduced density slurries. Thirdly, foam cements are sometimes used: for example, the addition of nitrogen plus a surfactant can create a mud with a density of 7–8 lbs/gal.
Slurry viscosity Sometimes it is necessary to use friction-reducing additives to assist the cement slurry in removing annular mud. Also, viscosity of the cement mixture may be required in order to ensure that it does not invade the formation. Interparticle friction reducers are basically dispersing agents that can reduce the apparent viscosity of the slurry. Salt is an example of a friction reducer.
Control of filtration rate In order to control the filtration rate it is helpful to form a very thin, tight filter cake. This can be achieved by adding materials such as bentonite and CMC to reduce the fluid loss from the cement slurry. Bentonite and CMC both have the ability to bind water chemically to their polar sites on the clay platelets or polymer molecules. Such additives help to provide protection against water loss by binding the free water in the slurry. It is common to run tests on the additives to ensure that they will meet the requirements of the specific situation.
Rheology of cement slurries It is important for a drilling operator to know the properties of the cement slurry. In most cases accurate predictions of the friction pressure are known. These help to avoid fracturing the lower stressed formations. Which can lead to a loss in circulation. It is often difficult to determine realistic rheological properties of cement slurries due to the variability of fluid properties.
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