The Expanding Role of Mud Logging
Peter Ablard For decades, samples and measurements obtained at the surface have provided mud Chris Bell Chevron North Sea Limited loggers with insights into conditions at the bit face. Information captured through Aberdeen, Scotland mud logging gave operators early indications of reservoir potential and even warned
David Cook of impending formation pressure problems. New sampling and analysis techniques, Ivan Fornasier Jean-Pierre Poyet along with advances in surface sensor design and monitoring, are bringing the Sachin Sharma science of mud logging into the 21st century. Roissy-en-France, France
Kevin Fielding Laura Lawton Hess Services UK Limited The mud logging unit has long been a common against deployment of wireline logging tools. In London, England wellsite fixture. First introduced commercially in such wells, analysis of mud gas and cuttings often 1939, these mobile laboratories carried little provided the first, and perhaps only, indication George Haines more than a coffee pot, a microscope for examin- that a formation might be productive. Today, Houston, Texas, USA ing formation cuttings and a hotwire sensor for although LWD technology is able to give the first detecting the amount of hydrocarbon gas encoun- glimpses of near-bit conditions in real time, Mark A. Herkommer tered while drilling. The mud logger’s job was to adverse wellbore conditions sometimes preclude Conroe, Texas record the depth and describe the lithology of the use of downhole logging tools. In such cases, formations that the drill bit encountered, then the mud log continues to inform operators of the Kevin McCarthy determine whether those formations contained producibility of their wells. At a minimum, the BP Exploration any oil or gas. mud log gives the operator an early indication of Houston, Texas Outside the logging unit, the mud logger’s zones that merit special attention, additional log- Maja Radakovic domain ranged from the shale shaker to the drill ging services or production tests. Sinopec-Addax floor. The shale shaker yielded formation cuttings The mud log serves a variety of functions. As a Geneva, Switzerland and gas—both liberated by the drill bit—which correlation tool, the mud log’s ROP and total gas were transported to the surface in the drilling curves exhibit a remarkable correspondence to Lawrence Umar fluid. Periodic visits to the shaker permitted the gamma ray and resistivity curves, respectively.1 Petronas Carigali Sdn Bhd mud logger to collect cuttings for microscopic Throughout the drilling process, mud logs pro- Kuala Lumpur, Malaysia examination, while a suction line between the vide real-time correlations with logs from neigh-
Oilfield Review Spring 2012: 24, no. 1. shaker and the logging unit carried gas from the boring wells and help the operator track the bit’s Copyright © 2012 Schlumberger. gas trap to the logging unit’s hotwire gas detec- position in relation to target formations. Because For help in preparation of this article, thanks to Justin tion system. Visits to the drill floor allowed the mud log is based on physical samples, it pro- Ashar, Kamel Benseddik, Regis Gallard, Willie Stoker and Craig Williamson, Houston; John Christie, Paris; Gen important exchanges of information between the vides direct, positive identification of lithology Herga and Denise Jackson, Gatwick, England; Mark Jayne, mud logger and driller. Using basic surface mea- and hydrocarbon content. This information can Francois Le buhan, Remi Lepoutre, Jacques Lessi, Audrey Malmin, Keith Ross and Philippe Verdenal, Roissy-en- surements, the mud logger was able to produce a be helpful when formation characteristics make France, France; Nikhil Patel, Singapore; and Irwan Roze, concise account of drilling activity. wireline or LWD log interpretation complicated Conroe, Texas. FLAIR, MDT, PreVue, RFT, StethoScope and Thema are For decades, gas measurements, lithology and or ambiguous. It can also fill gaps where other marks of Schlumberger. rate of penetration (ROP) provided the earliest such measurements have not been obtained. 1. Like electric logs, most mud logs conform to format indications of reservoir potential. Before the Thus, when integrated with wireline or LWD mea- standards set forth by the Society of Professional Well Log Analysts (SPWLA). For mud log standards advent of measurements while drilling (MWD) surements, cores and well test data, the mud log promulgated by SPWLA: Mercer RF and McAdams JB: and logging while drilling (LWD), mud loggers provides independent evidence for a more com- “Standards for Hydrocarbon Well Logging,” Transactions of the SPWLA 23rd Annual Logging Symposium, were able to obtain valuable formation data from prehensive understanding of reservoir conditions Corpus Christi, Texas, USA, July 6–9, 1982, paper LL. wells in which drilling conditions, formation and geology. characteristics or well trajectory conspired
24 Oilfield Review Drill floor Mud mixing pit Mud pumps
Suction pit
Sand trap Settling pit
Mud logging cabin Reserve pit
The scope of the basic mud logging service The mud logger’s role takes on added impor- From a drilling standpoint, the mud logger’s has broadened over time, as additional sensors tance when there is a drilling break, or signifi- most important task is gas monitoring. Mud gas brought more data into the logging unit— cant increase in ROP. Then the mud logger alerts trends that develop while drilling are integral to expanding in diversity from gas chromatographs the company representative and requests that evaluation of mud balance and identification of to weight-on-bit and mud pit level indicators. The drilling be stopped until mud and cuttings from potentially overpressured formations. By care- mud logging service now typically tracks ROP, the bit face can be circulated to the surface. If fully tracking gas and drilling parameters, the lithology, visual hydrocarbon indicators, total mud analysis indicates the presence of hydrocar- mud logger can recognize impending deviations combustible gas in mud and individual hydrocar- bons—called a show—the mud logger informs from normal trends and give advance warning so bon compounds in the gas, along with numerous the geologist, who may elect to core or test the the driller and company representative can miti- drilling parameters. As a hub for monitoring drill- interval. Geochemists and biostratigraphers also gate the problem by adjusting the density of the ing operations and rig sensors, the mud logging rely on mud loggers to collect representative drilling fluid or shutting in the well. Thus, the unit has become a source of crucial information samples needed to make correlations and develop success of a well and the safety of the drilling for the company representative, the driller and geologic models. operation may hinge on how quickly a mud logger the geologist. can synthesize and interpret myriad pieces of data.
Spring 2012 25 Mud logging capabilities have evolved over Advances in computing and networking tech- This article describes how a basic mud log is the years. By the mid-1950s, gas samples were nology, surface sensor design and sample analysis assembled, reviews sampling and analysis tech- being analyzed by wellsite gas chromatography. are bringing the mud logging unit into the 21st niques used in formation evaluation and dis- In the 1960s, mud logging companies began offer- century. Today, even more sensors lead into the cusses basic methods for monitoring pressure. An ing geopressure detection services.2 Automated logging unit, each acquiring data at a frequency of overview of recent sensor technology maps the event recorders, made possible through use of several times per second. To handle this increase evolutionary path from basic formation evalua- robust microelectronic components, were incor- in data volume, a context-aware processing sys- tion to advanced analysis of mud gases for geolo- porated into mud logging processes during the tem—based on computer-generated trend lines gists and well integrity services for drillers. 1970s. During the following decade, mud logging and a library of established models—makes the units entered the computer age. Computers took data easier for the mud logger and other end users Mechanics of Mud Logging the burden of printing the log away from the mud to comprehend. Digital images of samples viewed In the oil field, drilling fluid is integral to every drill- logger, who used to laboriously compile the data under the microscope can be rapidly transmitted ing project. Be it water-base, oil-base or gas-base, and then draw the log by hand. In addition, com- from the wellsite to the client office. And new drilling fluid is vital to the process of making hole: puters allowed mud loggers to organize and approaches to gas sampling and analysis have s )T STREAMS UNDER PRESSURE THROUGH JET NOZZLES track data from multiple sources without sen- been developed to extract geochemical properties on the drill bit to clean the bit and carry heat sory overload. at the wellsite. away from the bit face. s )T TRANSPORTS DRILL CUTTINGS FROM THE BIT FACE TO the surface, thus playing an essential role in the hole cleaning process. s )T OFFSETS BOTTOMHOLE PRESSURE TO HELP MAINTAIN Traveling block wellbore stability and prevent the influx of for- mation fluids that could cause blowouts. Over time, numerous variations on the basic Standpipe mixture of clay- and freshwater-base drilling flu- ids have been developed (and sometimes dis- Kelly Flowline carded). Well-known variations are based on Rotary table saltwater, mineral oil, diesel oil, polymers, nitro- Mud logging unit Gas trap gen, mist and foam. Each type has specific prop- Drill floor Suction line Shale shaker erties that deliver superior performance in Bell nipple certain drilling environments. And each requires Blowout preventer special accommodations when it comes to mud logging: Some require custom sampling tech- niques; others require special sample rinsing pro- Mud Suction Shaker Reserve cedures. This section focuses on the simplest of pump pit pit pit Casing environments, in which freshwater-base drilling muds are used. The practice of mud logging relies heavily on the mud circulation system, which carries forma- tion cuttings and fluids to the surface. High- Drillpipe pressure mud pumps draw drilling fluid from surface tanks and direct it downhole through the drillpipe (left). The mud exits the drillstring through nozzles at the face of the bit. Pump pres- sure forces the mud upward through the annular space between the drillpipe and casing, to exit at the surface through a flowline above the blowout Bit preventer. The mud then passes over a vibrating mesh screen at the shale shaker, where forma- > Mud circulation system. Drilling mud, drawn from the suction pit and pumped through surface pipe, tion cuttings are separated from the liquid mud. is sent downhole through the center of the drillpipe. It enters the open borehole through nozzles (not The mud falls through the screens to the mud pits shown) on the bit. The mud cools and lubricates the bit, then carries away formation cuttings and before being pumped back into the well. fluids as it moves upward in the annular space between the pipe and borehole wall. At the surface, the As a bit drills through the subsurface, the rock it mud, formation fluids and cuttings are diverted through a side outlet in the bell nipple and through an inclined flowline to the shale shaker. A mud agitator, or gas trap, is positioned at the shaker’s header grinds up—along with any water, oil or gas contained box to liberate gas from the mud. A suction line at the top of the agitator siphons gas off from the mud therein—is carried to the surface by the drilling and sends it to the mud logging unit for analysis. The mud flows over the shaker, where screens mud. What arrives at the surface and when it arrives separate the cuttings from the mud, which is returned to the shaker pit.
26 Oilfield Review are fundamental to the science of mud logging. The type of material and the timing of its arrival are influ- enced to varying degrees by drilling practices, lithol- ogy and pressure. The mud logger requires samples of formation cuttings to ascertain the subsurface geology at a given depth. Therefore, cuttings must be large enough to trap on the shaker or desilter screens. On average, rock cuttings are roughly the size of coffee grounds (right). Their size is controlled largely by how consolidated the rock is, along with grain size and cementation of the rock. In shale, pressure can affect the size of cuttings, and large elongated cavings of spalling shale that pop off the borehole wall are a strong indicator of overpressure. Bit type plays a significant role as well. Roller cone bits with chisel teeth produce a coarser grade of cuttings than do those with car- bide buttons. Polycrystalline diamond compact (PDC) bits in soft formations typically use large cutters that produce large cuttings (below right). Harder formations call for smaller PDC cutters, which produce smaller cuttings. > Cuttings sample. Having been cleaned and dried, these shale cuttings will be examined under The volume of cuttings that flow across the a microscope. shaker is a function of bit size and ROP.3 Bit size controls the cross-sectional area of the hole. ROP controls the thickness of the interval drilled over tings and fluid samples to the formations and and back to the surface is calculated so that the a given period. These factors are, in turn, affected depths from which they originate. mud logger can anticipate its arrival. The timer is by pump rate, weight on bit (WOB), rotary speed, One method for determining lag is to calcu- turned off when the tracer reaches the shale fluid viscosity and mud density, commonly late the amount of time required to displace the shaker. Knowing the pump rate and the inside referred to as mud weight (MW). total annular volume of drilling fluid. This method diameter of the drillpipe, the mud logger can cal- To characterize the lithology of a particular calls for the mud logger to factor in the length culate the fluid volume contained within the pipe interval in a well, the mud logger must account and diameter of the open hole, the capacity and to TD; then, knowing the pump displacement, the for the transport velocity of the cuttings to cor- displacement of the tubulars—riser, casing and number of strokes to pump the tracer downhole rectly determine the amount of time it takes the drillpipe—in addition to mud pump output, with can be calculated. The mud logger can convert cuttings to travel from the bit face to the shale separate calculations performed at each change this to the time it takes the tracer to travel from shaker. This lag time increases with depth, taking in hole or pipe diameter. However, the calculated the surface to the bit. Subtracting this time from just a few minutes while drilling the upper sec- result tends to be optimistic, underestimating the total measured time allows computation of tion of a well, but extending to several hours in hole volume because it does not account for the lag time from the drill bit to the surface. deeper sections. An accurate determination of rugosity or washouts, which affect mud volume lag time is crucial for precisely correlating cut- and velocity of flow. A more reliable method for determining lag 2. Geopressure is synonymous with formation pressure. In common oilfield parlance, the term refers to an anomalous time may be obtained through use of a tracer that fluid pressure condition that is above or below the normal is pumped downhole and detected upon its return hydrostatic pressure condition for a given depth. Normal pressure, overpressure or underpressure is either equal to the surface. Various tracer substances have to, above or below hydrostatic pressure, respectively. been tested, ranging from oats, corn or rice to For more on this topic: Barriol Y, Glaser KS, Pop J, Bartman B, Corbiell R, Eriksen KO, Laastad H, Laidlaw J, paint, calcium carbide nuggets or injected gas— Manin Y, Morrison K, Sayers CM, Terrazas Romero M and some types are precluded out of concern for their 8 in. Volokitin Y: “The Pressures of Drilling and Production,” effects on downhole equipment; others are used Oilfield Review 17, no. 3 (Autumn 2005): 22–41. Cutting with 3. Whittaker A: Mud Logging Handbook. Englewood Cliffs, only in certain regions.4 In most cases, the tracer tool marks New Jersey, USA: Prentice Hall, 1991. is simply wrapped in tissue paper, then inserted 4. Calcium carbide [CaC2] reacts with water in the drilling → fluid [CaC2+2H2O C2H2+Ca(OH)2]. The acetylene [C2H2] into the drillpipe when a connection is made on produced in this reaction is a gas not normally found in the drill floor. The paper disaggregates on its trip sediments. The acetylene will, in turn, be picked up at the gas trap, and its arrival will be noted automatically by the through the drillpipe and the tracer passes gas detector and gas chromatograph inside the mud through the nozzles in the bit. The mud logger > logging unit. Cuttings from a PDC bit. Claystone in a mud starts a timer when the pumps are turned on, and logger’s sieve shows tool marks, evidence of the time it takes the tracer to circulate downhole shearing action by a PDC bit.
Spring 2012 27 Clay Shale Sandstone Sand Limestone Dolomite Anhydrite Coal
FGFormation gas CGConnection gas TG Trip gas Oil and gas Oil Gas Bit change, trip Shoe
Chromatograph, ppm ROP ft/h Depth, Cuttings, Total Gas, units C1 C2 C3 Mud Weight, Lithological Description ft % iC4 nC4 ppg 100 50 0 0 125 250 375 500 and Notes iC nC 0.5k 1k 1.5k 2k 2.5k 5 5 Fluorescence 10 100 1k 10k 100k 1,000k 7,500 Sandstone: Clr-lt gy-frst, m-f gr, sbelg-elg, sbang-sbrnd, m srt, tr Glau, calc mtx, p-m cmt, qtzc i/p, m ind, fri-m hd, p-fr intgran por, no fluor.
7 9 /8-in. casing set at 7,580 ft MD/ 6,691 ft TVD. LOT = 14.8 ppg. In: 10.8 Clay: Lt brn-tan, arg, calc, plas, 7,600 Out: 10.8 sft, sol, slty, rthy, grty. Shale: Lt gy-lt brn, grnsh gy, arg, calc, frm-hd, occ sft, p-m cpt, sbblky-blky, Increase splty-ppy i/p, rthy, grty. Trip for new bit TG: 1,548 U 6.3 bbl gain MW to 11.3 Sandstone: Clr-lt gy-frst, m-f gr, sbelg-elg, sbang-sbrnd, m srt, tr Glau, calc mtx, p-m cmt, qtzc i/p, m ind, 7,700 CG: 35 U Increase MW to 11.5 fri-m hd, p-fr intgran por, no fluor.
CG: 39 U Increase Shale: Lt gy-lt brn, grnsh gy, arg, calc, MW to 11.7 frm-hd, occ sft, p-m cpt, sbblky-blky, CG: 45 U splty-ppy i/p, rthy, grty.
Clay: Lt brn-tan, arg, calc, plas, 7,800 sft, sol, stky i/p, rthy, grty. Sand: Clr-frst, trnsp-trnsl, m-c gr, WOB 38 to 53 klb occ f, sbelg-sbsph, ang-sbang, m srt, RPM 78 to 84 tr Glauc, uncons-p cmt, p ind, lse, n por, Flow 650 gpm Qtz, no fluor. FG: 427 U Clay: Lt brn-tan, arg, calc, plas, 7,900 sft, sol, stky i/p, rthy, grty. Increase Sand: Clr-frst, trnsp-trnsl, m-c gr, MW to 12.0 occ f, sbelg-sbsph, ang-sbang, m srt, FG: 920 U tr Glauc, uncons-p cmt, p ind, lse, Qtz, no fluor.
8,000 > Excerpt from a basic mud log. A mud log typically displays ROP, depth, cuttings lithology, gas measurements and cuttings descriptions. It may also contain notes on mud rheology or drilling parameters. This log documents fairly routine drilling, with casing set in a shaly interval at 7,580 ft. After drilling out of casing and running a leakoff test (LOT), ROP was about 25 to 30 ft/h [7.6 to 9 m/h]. A trip for a new bit at 7,650 ft resulted in 1,548 units of trip gas (TG). During drilling at near-balanced conditions, small increases in connection gas (CG) were observed following each connection, prompting the driller to raise the mud weight. An increase in ROP at 7,890 ft signified a drilling break, which was accompanied by increasing sand content and a gas show, which reached a peak of 920 units of gas (FG). Gas detector results are expressed in parts per million (ppm) of equivalent methane in air on a volume basis, where 10,000 ppm is equal to 1% methane, or 50 units. The wellsite gas chromatograph typically tracks methane [CH4]—denoted as C1—as well as the following constituents: ethane [C2H6] or C2, propane [C3H8] or C3 propane [C3H8] or C3 and the normal isopolymers of butane [C4H10] or nC4 and iC4 and pentane [C5H12] or nC5 and iC5.
Lag can also be measured in mud pump needed to pump the tracer downhole to the bit is calculated lag was 1,710 pump strokes, this 6% dif- strokes. Sensors placed on the mud pumps detect subtracted from the total count to determine the ference in lag time can be attributed to borehole piston movement and transmit a signal to the number of pump strokes required to circulate the 5. ECD is the effective density exerted at a given depth by pump stroke counter display in the mud logging mud and cuttings from the drill bit to the surface. circulating fluid against the formation. The ECD is unit. The counters are set to zero when the tracer Lag is usually measured on a daily basis and at calculated as: ECD = d + P/(0.052×D), where d is the mud weight in is inserted into the drillpipe and are read when each casing point. The calculated lag is useful in pounds per gallon (lbm/galUS); P is the pressure drop in the tracer arrives at the surface. A pump stroke determining the impact of formation washouts psi in the annulus between depth, D, and surface; D is the true vertical depth in ft and 0.052 is the conversion factor counter will add increments only when the pump between measured lag intervals. For example, a from psi/ft to lbm/galUS. is running; its rate thus reflects the true pumping carbide tracer is placed into the drillpipe during a 6. In this case, swabbing refers to a slight reduction in annular pressure caused by pipe movement during a rate, despite interruptions for connections or connection. After 1,800 pump strokes, the gas connection. The amount of gas produced into the pump maintenance. The number of pump strokes detectors record an acetylene peak. Given that the borehole as a result of swabbing depends on mud rheology, pipe velocity during movement and pipe and annulus diameter.
28 Oilfield Review enlargement. By multiplying pump displacement The mud log provides a condensed record of sub- formation cuttings. Deviations from this ROP by the difference in pump strokes, it is possible to surface geology, the hydrocarbons encountered baseline may indicate a change in lithology or determine the total volume of borehole washouts. and notable activities while drilling the well (pre- other downhole variables. For example, a drill- This volume is also used in extrapolating lag calcu- vious page). ing break may signify a change from shale to lations beyond the measured lag point. The ROP curve records how much time the bit sand or an increase in bottomhole pressure In some cases, another type of gas may help takes to penetrate each meter or foot, as deter- caused by crossing a fault. A sudden decrease in mud loggers keep track of lag. Connection gas is mined by a sensor on the drawworks. The ROP ROP, sometimes called a reverse drilling break, typically detected when drilling at near-balanced curve can be plotted as a step chart or a continu- may indicate a transition to rock of greater den- conditions in which pressure exerted by the mud is ous line, increasing from right to left. When dis- sity, or it may signal a problem with the bit. held close to formation pressure. When a connec- played in this manner, the ROP curve responds to These indicators must be weighed against other tion is made on the drill floor, the mud pumps are changes in rock type or porosity in much the measurements to ascertain their true cause. stopped and the pipe is picked up to bring the bit off same manner as a spontaneous potential or The lithology column is based on analysis of bottom. With pumps off, the effective mud weight is gamma ray curve, making for easy correlation lagged samples of cuttings. Samples are generally reduced from equivalent circulating density (ECD) between these curves. collected at regular intervals—for example, every to static mud weight, and the hole is swabbed some- A variety of factors affect ROP, including rock 3 m [10 ft] or every 10 m [30 ft]—and prior to trip- what as the pipe is picked up.5 These conditions can type, porosity, WOB, MW and rotary speed (rpm) ping out of the hole. They are also collected when create a reduction in bottomhole hydrostatic pres- as well as bit type, diameter and condition. ROP or gas curves exhibit significant deviations sure sufficient for small amounts of gas to be pro- Because drilling practices affect ROP as much as from established trends, indicating changes in for- duced by the formation.6 When present, this geology does, the mud logger makes note of cer- mation characteristics. The lithology column dis- connection gas is detected at one lag interval after tain drilling parameters next to the ROP curve, plays an estimate of gross lithology as a percentage a pipe connection. Each occurrence of connection especially when they change. of cuttings, reported in 10% increments. gas reflects the amount of lag for the depth of the The ROP curve is interpreted in the same The cuttings sample is rinsed and dried, then bit when the connection took place. manner as a gamma ray log. Typically, a shale examined under a binocular microscope. The baseline is established through a thick interval sample is then described in terms of lithology, Basic Formation Evaluation of generally slow, consistent drilling— the shale color, grain size, shape, sorting, porosity, texture In its most basic form, the mud log is a record of inference can be verified through analysis of and other characteristics relevant to the particu- the drill rate, cuttings lithology, total combusti- lar rock type (below). ble gas and individual hydrocarbon compounds brought to the surface during drilling operations.
Camera
Cuttings Sample Description
1. Rock name 2. Color 3. Hardness, fissility 4. Elements or grains Clastics Carbonates a. grain size a. “grain” nature b. roundness b. “grain” size c. sphericity d. sorting 5. Cement and matrix Clastics Carbonates a. abundance a. abundance b. nature b. crystallinity 6. Accessories, fossils 7. Visual porosity estimation 8. Hydrocarbon indications a. visual (stains and bleeding) b. direct fluorescence (extent, intensity and color) c. cut fluorescence (rate, intensity and color)
> Microscopic examination. Rinsed and dried samples are examined under a microscope (left) to provide lithological descriptions (right) for the mud log. The inset photograph shows a typical sample with a mix of rock types, dominated by gray claystone with a lesser fraction of clear to off-white sand. In some logging units, a camera is attached to the microscope. This allows the mud logger to thoroughly document potentially productive zones, uncommon minerals, distinctive marker beds or even metal shavings (indicative of casing or bit wear) found in the sample.
Spring 2012 29 > Fluorescence under UV light. Mineral fluorescence (light colors, left), often seen in rock samples, is not an indicator of pay. Streaming cut (center), however, is produced by an oil-bearing sample placed in solvent. Two faint streams of oil can be seen at the 5 o’clock and 11 o’clock positions on the sample. As this milky cut streams oil into the solvent, it gives the clear solvent a light blue hue. After the solvent is allowed to dry, any oil residue will produce a fluorescent ring on the sample glass (right), which is useful for detecting oil in low-permeability samples that do not readily produce streaming cut. (Photograph courtesy of G. Haines.)
The presence of hydrocarbons may not be green, gold, blue, yellow or white), intensity and by the solvent (above). The mud logger will note obvious—even under a microscope—so each distribution. Fluorescence color can indicate oil whether the cut is immediate or delayed, to pro- sample is subjected to a variety of simple tests to gravity, with dark colors suggestive of low–API vide a qualitative inference of permeability. screen for hydrocarbons. First, the sample is gravity, heavy oils, while light colors indicate Odor is another good indicator of hydrocar- examined under an ultraviolet (UV) light. high–API gravity, light oils. bons. If the drilling mud is ruled out as the source Fluorescence is an extremely sensitive test for Because fluorescence may be attributed to a of an oily odor, then the presence of hydrocar- the presence of hydrocarbons in mud, drill cut- number of causes, the cuttings that fluoresce are bons should be investigated. However, the lack of tings and cores. Sample fluorescence is evalu- separated from the main sample for further an odor is not diagnostic of an absence of hydro- ated in terms of color (ranging from brown to examination. Various mud additives, oil in the carbons, especially in gas zones. rock and certain types of minerals—such as Some rock grains may be stained through pyrite and calcite—may cause a sample to fluo- exposure to oil. The color of the stain can range resce. The mud logger must compare mud addi- from dark brown for low–API gravity oils, to col- tives against rock cuttings to recognize the orless for high–API gravity oils and condensate. effects of additives. Mineral fluorescence may The amount of staining or bleeding—the slow closely resemble oil fluorescence, but the differ- discharge of oil—in oil-bearing cuttings or cores Bubbles ence can be confirmed by application of a sol- is a qualitative measure of permeability. vent. Mineral fluorescence will remain Reaction to acid can be a sensitive indicator undisturbed, whereas hydrocarbon fluorescence of oil in carbonate rock samples, as long as oil- will appear to flow and diffuse into the solvent as base fluids or hydrocarbons were not added to Bubble the oil dissolves. This diffusion is known as cut the mud system. To test for oil, the mud logger fluorescence, or more commonly just cut. Under applies dilute hydrochloric acid to fragments of UV light, hydrocarbons may be seen to stream rock in a spot plate (left). The presence of oil is from the rock pores into the surrounding solvent, indicated by the formation of large bubbles as the turning the solvent cloudy. If no streaming cut is acid reacts with carbonate in the matrix to free observed, the sample is left until the solvent has the oil contained within the rock’s pores. In some > Reaction of carbonate rock to acid. Dilute evaporated and then examined once more under cases, the oil will display an iridescent rainbow hydrochloric acid dissolves carbonate rock, UV light. A fluorescent ring around the sample on the bubble’s surface. liberating any oil contained within. As it dissipates, the oil turns the clear acid brown. The three indicates that hydrocarbons have been liberated larger bubbles are a result of greater surface tension caused by the presence of oil.
30 Oilfield Review Wettability can be qualitatively assessed. type to another. The quantity of the gas recovered Failure of a sample to take on water, or the ten- and the ratios of the various gases are useful in R log dency of cuttings to float in water, may indicate identifying zones of producible oil or gas.8 60N that oil is present and that the sample is oil wet.7 d = However, samples from air-drilled wells may not Basic Pressure Monitoring 12W log 6 wet as a result of small particle sizes and surface Drilling crews around the world have had to con- 10 D tension effects. tend with abnormally high formation pressures. A positive result from any of these screening High pressures are encountered in formations in where: d = drillability exponent tests is considered an oil show, which warrants which an impermeable layer, sealing fault, diapir R = penetration rate, ft/h N = rotary speed, rpm immediate notification of the company repre- or other barrier restricts natural fluid flow and W = weight on bit, lbm sentative and geologist. The mud logger also pressure equilibration. In these overpressured D = bit diameter, in. watches for gas shows by monitoring the gas formations, fluids trapped in the pores bear part detection equipment. of the weight of the overlying rock. Overpressure > Formula for d-exponent. The d-exponent The gas detection system offers near-instan- commonly occurs when low permeability pre- normalizes the variables that can influence the taneous readings, limited only by the lag time vents pore fluid from escaping as rapidly as drilling rate, making the resulting plot more from the bit to the surface. Suction lines trans- required for compaction of pore space under the sensitive to pore pressure. (Adapted from Jorden and Shirley, reference 11). The d-exponent varies port a constant stream of air and gas from the gas weight of newly deposited overburden sediments. inversely with the rate of penetration. Variations trap, located at the shale shaker, to the logging Excess pressure builds as the weight of overbur- on the original equation have been developed unit. There, sensitive gas detection instruments den squeezes the trapped fluid in a process since its publication in 1966; these variations process samples extracted from the drilling mud. referred to as undercompaction or compaction account for changes in mud weight or bit wear. (Rehm and McClendon, reference 12.) The primary tool is a flame ionization detector disequilibrium. This undercompaction typically (FID), which can sense hydrocarbon gas concen- occurs where there is a transition from a sand- trations as low as 5 to 20 ppm. FID results are prone to a shale-prone environment.9 Shale porosity has long been considered a expressed in parts per million (ppm) of equiva- Detection of overpressured formations is crit- reliable indicator of abnormal formation pres- lent methane in air on a volume basis, where ical to the drilling process; by providing this ser- sure. Because the weight of overburden causes 10,000 ppm is equal to 1% methane, or 50 units. vice, mud logging plays an important role in well shale to become more compact with depth, ROP The FID measurements are used to plot the control. Drillers are extremely keen to recognize normally decreases with depth. If the drilling total gas curve on the mud log. Background impending threats to well control, but the sim- rate increases in shale, the driller and mud log- gas—a more or less constant, minimum level of plicity of rig floor instrumentation sometimes ger might reasonably suspect that porosity is gas—establishes a baseline on the total gas makes it difficult to identify subtle changes in increasing and that the bit may be entering an plot. The level of background gas may be any pressure parameters. An unnoticed failure of a overpressured zone. value from a few ppm to several percent, sensor or display on the drill floor, a distraction at However, numerous factors influence ROP; depending on formation and circulating condi- the wrong time or an unexpected change in drill- weight on bit, mud weight, rotary speed, bit size tions. A gas show is any significant increase in ing routine may prevent a driller from recogniz- and bit condition also affect drilling rate.11 To detected gas, usually also correlated with a zone ing the onset of a dangerous situation. Using account for these mechanical variables, the mud of increased porosity or permeability. surface indicators, mud loggers may be able to logger computes a drillability exponent, or The mud logger consults the gas chromato- identify hazardous operating conditions. d-exponent (above). Some mud loggers use a graph for more detailed analysis during oil or gas Mud logging crews provide another set of eyes corrected d-exponent (dcs), which factors in shows. Operating on an automated cycle, the to monitor drilling systems while correlating mul- 7. Wettability is the preference of a solid surface to be in chromatograph separates the gas stream into dif- tiple drilling parameters. Through examination contact with one liquid rather than another. ferent fractions according to molecular weight. of cuttings and diligent monitoring of ROP, gas, Intermolecular interactions between the solid surface and the liquid control wetting behavior. Cycle time—the amount of time it takes to cycle mud weight, bulk shale density and mud pit vol- For more on wettability: Abdallah W, Buckley JS, a gas sample through the chromatograph col- ume, mud loggers can frequently detect a transi- Carnegie A, Edwards J, Herold B, Fordham E, Graue A, Habashy T, Seleznev N, Signer C, Hussain H, Montaron B umn—may range from less than a minute to sev- tion from normal to potentially dangerous and Ziauddin M: “Fundamentals of Wettability,” eral minutes, depending on the type of gas pressure conditions. Oilfield Review 19, no. 2 (Summer 2007): 44–61. separation column used in the chromatograph. As the bit approaches an overpressured for- 8. For more on chromatography and gas ratio analysis: Haworth JH, Sellens M and Whittaker A: “Interpretation Commonly detected components fall within the mation, distinct changes in compaction and of Hydrocarbon Shows Using Light (C1–C5) Hydrocarbon alkane group: methane [C ], ethane [C ], pro- porosity may be observed. Formation pressure Gases from Mud-Log Data,” AAPG Bulletin 69, no. 8 1 2 (August 1985): 1305–1310. pane [C3], butane [C4] and pentane [C5]. The may approach that of the bottomhole pressure 9. Bowers GL: “Detecting High Overpressure,” The Leading measurement of these light hydrocarbons helps (BHP). When this pressure difference decreases, Edge 21, no. 2 (February 2002): 174–177. geologists characterize reservoir fluid composi- ROP increases as normally overbalanced bottom- 10. Dickey PA: “Pressure Detection: Part 3. Wellsite Methods,” in Morton-Thompson D and Woods AM (eds): tion while drilling. Because each reservoir fluid is hole conditions start to become underbalanced.10 Development Geology Reference Manual. Tulsa: The composed of different hydrocarbon species with Consequently, ROP is a key parameter in the American Association of Petroleum Geologists, AAPG Methods in Exploration Series no. 10 (1992): 79–82. differing molecular weights, the relative propor- detection of overpressured formations. 11. Jorden JR and Shirley OJ: “Application of Drilling tions of light hydrocarbons change from one fluid Performance Data to Overpressure Detection,” Journal of Petroleum Technology 18, no. 11 (November 1966): 1387–1394.
Spring 2012 31 level drops too far, the decrease in the hydrostatic pressure downhole may allow formation fluids to enter the wellbore, causing a kick similar to drill- Rate of d-exponent Formation ing into an overpressured zone. penetration pressure A kick may also be indicated by an increase gradient or decrease in drillstring weight. A small infu- sion of formation fluid can reduce the buoyancy of the fluid in the annulus; a sensitive weight
Depth Normally sensor may indicate this change as an increase pressured zone in drillstring weight. Given a substantial kick, Transition zone however, formation fluid may enter the borehole with enough force to push the drillpipe upward, Overpressured causing a marked decrease in indicated drill- zone string weight. The ability to warn drilling crews of impend- ing trouble is heavily dependent on the mud log- Increasing drilling rate, d-exponent and formation pressure gradient ger’s capacity for monitoring changes in drilling > Effects of overpressure on drilling rate and d-exponent. Through a normally parameters. This capability could never have pressured shale interval, ROP (red line) generally decreases with depth. The been realized without the extra layer of hyper- d-exponent (blue line) tends to increase with depth, following a normal compaction trend. Deviations from these trends may be related to vigilance derived from numerous sensors undercompaction and may signal that the bit is encroaching on an installed at critical points around the rig. overpressured zone. Moving into the 21st Century Early mud loggers grew attuned to the sounds of the drilling rig and could often tell what was hap- pening simply by the clang of the driller’s tongs, changes in mud weight or bit wear.12 After calcu- rise as a result of methane dissolved in the pore the revving of the drawworks engine and the lating the d-exponent to normalize the ROP, the water of some overpressured shales. Gas escap- squeal of the driller’s brake. Any variation in the mud logger can view drillability as a function of ing from the cuttings is detected at the mud log- normal routine and rhythms of the rig was cause rock strength and the density of the drilling fluid. ging unit as an increase in total gas. This indicator for investigation. Today, robust, highly sophisti- As compaction and rock strength increase may be misleading, however, because increases cated sensors acquire data at several times per with depth, the d-exponent increases when drill- in total gas may result from oil- or gas-bearing second while a context-aware processing system ing through a uniform lithology with no changes formations or organic-rich shales. The increase helps the mud logger piece it all together. in mud overbalance or bit performance. A plot of in porosity that is characteristic of undercom- Through the years, an impressive array of sen- the d-exponent with depth should roughly mirror pacted shales causes lower shale density than is sors has been developed or adapted for use by the ROP, showing an inverse relation to the drill found in normally compacted shales. The mud advanced mud logging companies. One such com- rate (above). A drilling break would plot as a logger uses a density measuring device in the log- pany, Geoservices, a Schlumberger company, is reversal in the slope of the d-exponent. ging unit to determine the density of shale cut- an industry leader in mud logging technology.15 The arrival of gas in the mud is another indi- tings at regular intervals.13 Over its 53-year history, Geoservices has devel- cation of compaction disequilibrium. If formation An increase in return flow, coupled with rising oped or acquired a wide variety of sensors to mea- pressure exceeds the pressure applied by the col- levels in the mud tanks, indicates a reflux of drill- sure and record critical drilling performance and umn of mud, formation fluids will begin to flow ing fluids, with greater volumes of mud flowing circulation system parameters. Most sensors are into the wellbore. A rapid influx of fluids is called out of the hole than were pumped into it. Pit level intrinsically safe for operating in hazardous con- a kick, and marks the beginning of serious well and flow rate sensors monitored at the drill floor ditions and must be robustly constructed to control problems. If formation fluid—especially and logging unit will trigger an alarm when they ensure reliable operation in harsh drilling envi- gas—flows into the wellbore unabated, the detect a mud level change, prompting the drilling ronments and climates. Sensor signals are con- effects will soon cascade. The influx will lower crew to shut off the mud pumps, check for flow verted from analog to digital as close to the the overall mud column weight, reducing the and prepare to close the blowout preventer. 12. Rehm B and McClendon R: “Measurement of Formation effective pressure against the flowing formation, At the opposite end of the spectrum is a Pressure from Drilling Data,” paper SPE 3601, thereby permitting the formation to flow at a decrease in mud levels, which indicates that the presented at the SPE Annual Meeting, New Orleans, October 3–6, 1971. greater rate, leading to a blowout. mud pumps are sending more fluid downhole Lyons WC (ed): Standard Handbook of Petroleum & Mud loggers must try to interpret overpres- than is being circulated back to the surface. This Natural Gas Engineering, vol 2. Houston: Gulf Professional Publishing (1996): 1045. sure clues from a number of parameters. An lost circulation may indicate that the formation 13. Dickey, reference 10. increase in the temperature of the mud returns has fractured and can have serious repercussions, 14. For more on mud loss prevention and remediation: may result from faster drilling and increased cav- depending on the rate of fluid loss.14 If the mud Cook J, Growcock F, Guo Q, Hodder M and van Oort E: “Stabilizing the Wellbore to Prevent Lost Circulation,” ings in undercompacted shales. Gas levels may Oilfield Review 23, no. 4 (Winter 2011/2012): 26–35. 15. Geoservices was acquired by Schlumberger in 2010.
32 Oilfield Review sensor as possible to prevent problems associ- Density sensors provide rapid, accurate mea- ated with analog signal transmission and a multi- surements of drilling fluid density; they can tude of cables running across the rig floor. detect slight changes in mud weight, enabling Pressure sensors measure a variety of crucial the mud logger to alert the drilling crew to an parameters. These sensors can be fitted to key influx of lower-density formation fluids into the pieces of rig equipment to obtain measurements well. The density sensors are also used to monitor such as weight on hook, WOB, rotary torque, the addition of weighting material or fluid to the standpipe pressure, casing pressure and cement mud system. Mud density is measured by two unit pressure. pressure sensors immersed at different depths in By measuring small movements of the draw- the mud pit and calculated from the pressure dif- > works drum, the drawworks sensor helps the mud ferential and depth between the sensors. Drawworks sensor. This sensor consists of a disk logger track the movement of the drillstring and Three types of flow sensors are available for that rotates in harmony with movements of the cable drum. Movements of the disk are detected the position of the bit while drilling or tripping continuous monitoring of drilling fluid flow: by proximity sensors, which send pulses to the (right). This sensor is fitted onto the main shaft s 4HE MUD mOW PADDLE MEASURES THE HEIGHT OF main processor in the logging unit. of the drawworks. Drawworks sensor outputs the mud in the mud return flowline. When con- help the mud logger determine drilling rate, hook nected to the logging system computer, the sen- position and bit position. sor provides a continuous chart of relative Noncontact proximity sensors monitor pump height. The mud logger can set alarms for flow strokes and rotary speed. Pump strokes are used height above and below preselected limits. to calculate mud flow rates, which are essential s 4HE ELECTROMAGNETIC mOWMETER IS A VOLUMETRIC creating a potential difference between the for optimization of drilling hydraulics, estimation flowmeter that operates on the principle of two electrodes that is proportional to the fluid of lag time and various kick control functions. magnetic induction. It can be installed on the flow rate. The electromagnetic flowmeter Monitoring of rotary speed (rpm) is necessary for standpipe to measure flow into the well and on operates in water-base muds or in muds in assessing drilling performance and calculating the return flowline to measure flow out of the which the continuous phase is conductive. the d-exponent. The proximity sensor emits an wellbore. Each sensor unit replaces a short Connection to the logging system computer electromagnetic (EM) field and uses EM induc- section of the pipe on which it is mounted. enables real-time monitoring and permanent tion to detect the passage of a metal activator. Each sensor consists of a pair of circular recording of the flow parameters as well as Variations in rotary torque often provide the electrodes flush with the inside of the pipe. automated calculation of differential flow, first indications of problems with downhole drill- When the sensor is energized, a magnetic field which is essential for reliable detection of ing equipment. For a given rotary speed, a grad- is established at right angles to the pipe axis, small-volume kicks or losses. ual increase in torque might signal that the drill bit is worn and should be replaced. Mud loggers can also use torque variations to identify forma- tion changes while drilling. A rotary torque sen- sor uses a transducer, which is clamped around the cable feeding the electric motor that powers the rotary table or topdrive. The electric current drawn by the motor is proportional to the rotary torque applied to the drillstring. Mud pit Detection of changes in mud pit level is key to the safety of the drilling process. The ultrasonic pit level sensor is positioned over the mud pits and measures fluid level. This sensor emits an ultrasonic wave that reflects off the surface of the liquid (right). This sensor is light, compact, accu- rate and highly reliable, requiring no moving or immersed parts. Precise measurement of the time it takes for the ultrasonic signal to return to the sensor gives the distance between the sensor and the level of liquid in the pit. On floating rigs, multiple sensors may be installed in each pit to account for variations in mud level caused by ocean wave motion. > Pit level sensor. This device (inset) emits a series of ultrasonic pulses to detect changes in fluid level in the mud pit.
Spring 2012 33 No flow Flow inlet No flow Top view
Inlet pickoff
Inlet side Outlet pickoff Magnet
Flow outlet
Sine wave Outlet side
No flow Flow
Inlet pickoff
Δt Inlet side Outlet pickoff
Inlet side
Out of phase In phase
Outlet side Outlet side
> Coriolis flowmeter. Coriolis meters are installed in the flowline. When there is no flow, current through the pickoffs (top left), generates sine waves on both inlet and outlet sides of the meter (bottom left and top right) that are in phase with each other. Fluid moving through the tubes causes them to twist in opposing directions (bottom right) and also causes the sine waves to go out of phase by a factor Δt, which can be converted to mass flow rate.
s 4HE #ORIOLIS mOWMETER ACCURATELY MEASURES BOX TO OBTAIN mOWLINE TEMPERATURE DESIGNATED Advanced Services MASS mOW TEMPERATURE AND DENSITY OF A CIRCU- AS hTEMPERATURE OUTv &ROM THE DIFFERENCE BETWEEN .EW SENSOR TECHNOLOGY IS PAVING THE WAY FOR LATING mUID GAS OR SLURRY AT LOW TO MODERATE hOUTv AND hINv VALUES THE TEMPERATURE GRADIENT CAN IMPROVING DRILLING PERFORMANCE AND INCREASING PRESSURES 4HE SENSOR TYPICALLY INSTALLED ON A BE CALCULATED TO HELP LOGGING CREWS LOCATE TRANSITION THE VALUE OF THE DATA EXTRACTED FROM THE MUD BYPASS CHANNEL ADDED TO THE RETURN mOWLINE ZONES AND OTHER GEOLOGIC BOUNDARIES 'EOSERVICES MUD LOGGING TECHNOLOGY IS FOCUSED USES THE #ORIOLIS EFFECT TO MEASURE mOW 4HE RESISTIVITY SENSOR MEASURES DRILLING mUID ON TWO MAIN AREAS FORMATION EVALUATION AND ABOVE &LUID ENTERS THE SENSOR AND PASSES ELECTRICAL RESISTIVITY WHICH REmECTS THE SALINITY OF DRILLING SUPPORT THROUGH A PAIR OF mOW TUBES WHICH ARE FREE TO THE mUID 4HE SENSORS ARE INSTALLED IN THE SUCTION &ORMATION EVALUATION SERVICES CAN NOW GO VIBRATE AND TWIST UNDER THE INmUENCE OF THE PIT AND SHALE SHAKER HEADER BOX -UD SALINITY BEYOND ANALYSES OF ROCK CUTTINGS AND mUIDS TO mUID mOW &LOW IS MEASURED BY QUANTIFYING THE MAY CHANGE WHEN DRILLING THROUGH BEDDED SALTS IDENTIFY LITHOLOGY AND POTENTIAL PAY ZONES 4O SUP- AMOUNT OF TWIST IN THE mOW TUBES WHICH IS PRO- OR SALT DOMES WHEN PASSING THROUGH FAULT ZONES PLY ADVANCED MUD GAS SAMPLING AND CHROMATOG- PORTIONAL TO THE MASS mOW RATE OF THE mUID 4HE AND WHEN DRILLING ZONES OF TRANSITION TO ABNORMAL RAPHY 'EOSERVICES HAS DEVELOPED THE &,!)2 mUID DENSITY OF THE mUID IS OBTAINED BY MEASURING PRESSURES WHERE FORMATION WATER mOWS INTO THE LOGGING AND ANALYSIS SERVICE FOR WELLSITE GEOCHEM- THE RESONANT FREQUENCY OF VIBRATION OF THE mOW MUD COLUMN 4HIS SYSTEM ENABLES ACCURATE AND ICAL EVALUATION $RILLING SUPPORT SERVICES PROVIDE TUBES 4HE MEASURED VALUES ARE AUTOMATICALLY LINEAR MEASUREMENT OF CONDUCTIVITY FROM TO A LEVEL OF ANALYSIS OF SURFACE DATABEYOND THAT OF COMPENSATED FOR TEMPERATURE CHANGES M3 BASIC PRESSURE MONITORING SERVICESTO ENHANCE 4HE TEMPERATURE OF THE CIRCULATING DRILLING 4ODAYS MUD LOGGING UNITS MONITOR A WIDE SAFETY AND OPTIMIZE DRILLING OPERATIONS 4HE mUID CAN PROVIDE CLUES TO CHANGING DOWNHOLE RANGE OF SURFACE SENSORS USED TO ASCERTAIN DOWN- 0RE6UE REAL TIME GEOPRESSURE SERVICE IS DESIGNED CONDITIONS 4EMPERATURE SENSORS ARE USUALLY HOLE CONDITIONS OR EVALUATE RIG PERFORMANCE TO HELP REDUCE THE RISKS OF KICKS MUD LOSSES AND PLACED IN THE SUCTION MUD PIT DESIGNATED AS 4HESE SENSORS ENABLE THE MUD LOGGER TO RECOGNIZE OTHER WELL CONTROL PROBLEMS !ND 4HEMA DRILLING hTEMPERATURE INv AND IN THE SHALE SHAKER HEADER CHANGING CONDITIONS THAT COULD ENHANCE OR JEOP- OPERATIONS SUPPORT AND ANALYSIS SERVICE PROVIDES ARDIZE A PROSPECT
34 Oilfield Review up-to-date analysis of drilling mechanics, hole Swivel FLEX out condition and rig performance. Hose FLAIR advanced mud gas logging—During Mud Kelly pump the past 10 years, advances in mud logging tech- Analyzer nology have significantly improved the quality Results and utility of wellsite formation evaluation data. Fluid coming from the well Today, high-resolution gas chromatography and Shale Mud pit shakers mass spectrometry provide data and interpreta- tive capabilities that enable quantitative evalua- tions of key formation parameters. FLAIR fluid Drillstring FLEX in Fluids data interpretation logging and analysis in real time gives early infor- Gas chromatograph Facies determination Cuttings mation pertaining to formation fluid composi- Mass spectrometer Fluid composition tion. Integration of FLAIR data with data Bit obtained by other formation evaluation tech- Fluid pumped back into the well niques enables more-accurate assessments of hydrocarbons in the formation. > Arrangement of FLEX extraction units. Using specialized gas extraction units placed in the discharge The FLAIR system analyzes hydrocarbons and suction lines, the FLAIR analysis system compares the two gas streams to correct for any recycled gas that the mud system’s degassing units failed to remove. extracted from the drilling mud under constant thermodynamic conditions. These hydrocarbons are continuously analyzed to obtain a quantitative evaluation of the light gases C1 through C5, while also providing qualitative information on heavier components C6 through C8, including methylcyclo- inherent energy in the system to efficiently liber- Comparisons between pressure-volume-tem- hexane and the light aromatics benzene and tolu- ate the heavier gas components from the mud. perature (PVT) analysis of actual downhole fluids 16 ene. Other nonhydrocarbon components, such as Traditional mud gas extractors that do not heat with results obtained through FLAIR analysis of C1 helium, hydrogen, carbon dioxide and hydrogen the sample may yield inaccurate data because to C5 components show a close match. This capa- sulfide can also be monitored. more of the gas is left in the mud during the bility was demonstrated during a collaboration Specialized mud gas extraction equipment is extraction process. between Shell and Geoservices, in which PVT and a key component of the FLAIR system. The FLEX With the FLEX extraction process, the FLAIR data from Gulf of Mexico wells were found fluid extractor continuously samples mud from FLAIR mud gas logging system operates under to be comparable, whereas a traditional mud gas the flowline as the mud returns from the well. constant thermodynamic conditions, enabling logging system consistently underestimated the 17 The FLEX extractor heats mud samples to a con- calibration of the extraction efficiency for the concentrations of the C2+ gas species. stant temperature under constant pressure and C1 to C5 components. The heavier hydrocarbons, Among other capabilities, the FLAIR service volume conditions. This method provides a C6 to C8, are not as easily extracted, but their can help geoscientists differentiate between dif- steady air-to-mud ratio inside the extraction presence can be detected qualitatively. The cali- ferent fluid types. As a bit penetrates a reservoir, chamber, creating an extremely efficient and bration is coupled with a correction that an increase in gas density measured at the sur- repeatable process. The capability to heat the accounts for any gas that might have been recy- face may indicate a transition from gas cap to sample can be particularly important in deepwa- cled through the mud system. This is achieved oil leg. This increased density is caused by a ter environments, where mud return tempera- by placing a second FLEX unit in the pump suc- proportional increase in heavier gases (C3+) tures may range from 10°C to 15°C [50°F to tion line, the point at which the mud is pumped compared with the lighter C1 and C2 components. 59°F]. At low temperatures, there is not enough back into the well (above). In this manner, the Measurements of heavy components and their fraction of hydrocarbons recycled with the mud relative proportions to the light fraction are used 16. Light hydrocarbons such as C1 to C5 are easily removed by the mud gas extraction process, so their concentrations and pumped back into the well can be quantita- to calculate the hydrocarbon balance (Bh) and can be assessed quantitatively. The heavier C6 to C8 tively measured. Correction for recycled gas is wetness (Wh) ratios, which help geoscientists hydrocarbons are more difficult to remove from the fluid by this process. Their presence can be detected possible because the extraction conditions are discriminate between oil and gas.18 but not easily quantified, so a qualitative measurement the same for both FLEX units. The FLAIR service was run on an offshore UK is provided. 17. McKinney D, Flannery M, Elshahawi H, Stankiewicz A, Extracted hydrocarbons are fed to an appraisal well drilled for Hess Corporation and Clarke E, Breviere J and Sharma S: “Advanced Mud Gas advanced gas chromatograph–mass spectrome- partners Chevron, DONG Energy and OMV. Two of Logging in Combination with Wireline Formation Testing and Geochemical Fingerprinting for an Improved ter (GCMS) analyzer, which detects and analyzes the operator’s key objectives for the well were to Understanding of Reservoir Architecture,” paper gases at the parts-per-million (or micrograms- confirm the volume of hydrocarbons in place SPE 109861, presented at the SPE Annual Technical Conference and Exhibition, Anaheim, California, USA, per-gram) level. The mass spectrometer enables within the main reservoir and to investigate the November 11–14, 2007. the FLAIR analyzer to detect and differentiate presence of hydrocarbons in certain formations 18. Bh = [(C1 + C2) / (C3 + iC4 + nC4 + C5)]. between coeluting peaks created by the various above and below this reservoir. After the pilot Wh = [(C2 + C3 + C4 + C5) / (C1 + C2 + C3 + C4 + C5)] × 100. For more on these ratios and their interpretation: ion currents that characterize components hole was successfully drilled, a sidetrack was Haworth et al, reference 8. extracted from the mud. This leads to a very short drilled and the well was landed horizontally in
analysis time—85 s for analysis up to C8, includ- the main reservoir target interval, designated as ing differentiation of several isomers.
Spring 2012 35 The FLAIR service also helped the operator C1/C2 evaluate a formation’s potential for producing oil or gas. The ratio of heavy to light fractions was used to calculate the hydrocarbon balance and iC /nC C /C 4 4 1 3 wetness ratios. Another potential indicator was Fluid facies, % C1 the appearance of methylcyclohexane [C7H14], a 2a: 90% member of the naphthenic family that usually is 2b: 92% present in the liquid phase (next page). 3a: 95% to 96% In addition, the operator sought to distin- 3b: 92% to 93% guish between biodegraded and nonbiodegraded C /C s C /C s 3 4 1 4 3c: 90% to 91% fluids in the reservoir. Biodegradation can affect 3d: 88% to 89% both the quality of hydrocarbons and their pro- 3e: 86% to 87% ducibility.19 Among other effects, biodegradation 3f: 85% to 86% C2/C4s can raise oil viscosity, decrease API gravity and increase asphaltene, sulfur and metals content. > Fluid facies characterization. Variations in fluid composition produce In addition, biogenic gas may override oil in a res- distinctive star plots that can be classified as different fluid facies. This star diagram highlights different levels of heterogeneity. The lightest fluid was ervoir, moving updip to disrupt existing reservoir encountered in the 3a facies, whereas heaviest fluids were found in facies fluid gradients. This influx modifies the gas/oil 3e and 3f. ratio, creating compositional variations. Gradient disruptions from charging and recharging may indicate the presence of compartments. the S3 horizon. The sidetrack well raised a num- these zones helped the operator divide them into In a study conducted prior to spudding the ber of questions pertaining to vertical connectiv- distinctive fluid facies. These facies were defined well, Hess evaluated PVT analyses obtained ity, fluid variability, presence of altered and by graphing gas ratios on star diagrams—multi- from offset wells to assess the effects of bio- unaltered fluids and geosteering uncertainties variate plots in polar coordinates—to depict degradation in the reservoir. These analyses within the horizontal section. chemical composition and highlight their differ- helped to identify markers that could prove Hess investigated potential hydrocarbon ences (above). Based on these analyses, the useful in recognizing alterations resulting zones where gas peaks were recorded above operator identified several distinct fluid facies from biodegradation. The study indicated that background level. FLAIR analysis of gases from from different horizons within the well. specific ratios of heptane [nC7], methylcyclo- hexane [C7H14] and toluene [C7H8] were com- mon to the wells in which biodegradation was
observed. The C2/C3 ratio was found to be 2.500 another useful indicator of early-stage biodeg-
radation because C3 is one of the first compo- Upper reservoir nents that bacteria attack and remove; in a
later stage they remove the C2. FLAIR analysis provided quantitative compo- 1.875 Deeper reservoir sition only in the C1 to C5 range and provided qualitative evaluations of the heavier hydrocar- bons. In the Hess well, these results showed low
values of the nC7/C7H14 ratio, which is in line with 3 /C
2 1.250 biodegradation effects observed in reservoir flu- C ids from offset wells. When extremely low values of toluene were detected—close to the sensitiv- ity of the analyzer—a change in the analysis rou- Biodegraded fluid, pilot hole tine was called for. The C7H8/nC7 ratio was 0.625 Biodegraded fluid, sidetrack well replaced by a C2/C3 ratio, providing a clear dif- Nonbiodegraded fluid, sidetrack well ferentiation between biodegraded and unaltered fluids (left).
19. For more on biodegradation in the reservoir: Creek J, Cribbs M, Dong C, Mullins OC, Elshahawi H, Hegeman P, 0 O’Keefe M, Peters K and Zuo JY: “Downhole Fluids 0 0.25 0.50 0.75 1.00 Laboratory,” Oilfield Review 21, no. 4 (Winter 2009/2010): nC7/C7H14 38–54. > Recognizing fluid differences. Hess scientists identified two distinct fluid families, based on the level of fluid alteration. The hydrocarbon ratio analysis confirmed the fluid in an upper reservoir was biodegraded, whereas the fluid in a deeper reservoir in the well was unaltered.
36 Oilfield Review Vertical Depth X,100ft X,700
Gamma Ray C3 nC4 nC5 nC7 C7H14 Bh –50gAPI 150 0ppm 500 0ppm 150 0ppm 100 0ppm 100 0ppm 250 0 100
C1 C2 iC4 iC5 nC6 C7H8 Wh
Lithology Formation Fluid Facies 0ppm 10k 0ppm 500 0ppm 150 0ppm 100 0ppm 100 050ppm 0 100
R2 2a
Oil 2b 2a R3 2b
S1 3a Coalgl as 3b 3c S2 Oil
T1 3a Coallgas 3b
3a T1 Coal gas 3b
3d
3e
Oil
3e S3
3f
Lithology
Clay Sand Coal
Fluid facies, % C1 2a: 90% 2b: 92% 3a: 95% to 96% 3b: 92% to 93% 3c: 90% to 91% 3d: 88% to 89% 3e: 86% to 87% 3f: 85% to 86%
> Fluid facies log. Precise hydrocarbon measurements are obtained through FLAIR gas analyses and are used to distinguish between fluids produced from different reservoir intervals. The resulting fluid facies are numbered sequentially, with a letter indicating subfacies (Track 3 and legend). Measurements of the C1 to C7 components (Tracks 4 to 8) are used to calculate hydrocarbon balance (Bh) and wetness (Wh) ratios (Track 10). In this well, methylcyclohexane [C7H14] was also useful in determining the presence of a liquid phase (Track 9). The R2 and R3 formations (Track 2) are characterized by fluid facies 2, while the other formations contain fluids from facies 3. The targeted S3 reservoir was fairly homogeneous, its fluids being relatively light in the C1 to C5 range, but with a proportionally higher abundance of C7H14, which suggested the presence of a liquid phase. The coal seams S1 and T1 were consistently characterized by high gas levels, with the gas ranging between 95% and 96% C1—but without methylcyclohexane.
Spring 2012 37 200 200 Resistivity decrease ohm.m ohm.m Resistivity Deep Resistivity Shallow 0.2 0.2 1 C ppm gAPI Gamma Ray 0 15k –50 150 T1 T1
Formation S2 S3
Lithology
> LWD log. During drilling through the reservoir section, FLAIR gas analysis (Track 3) helped to ease concerns about a decrease in resistivity. FLAIR analysis confirmed that the well had not exited the reservoir zone.
The FLAIR services also proved useful as an After creating a 3D seismic interval velocity regimes. The sonic velocity, density and resistiv- aid to geosteering. While the horizontal sec- model from local and regional seismic data, the ity logs are especially useful for pore pressure tion was being drilled, a decrease in resistivity pressure specialists calibrate the model using and fracture gradient interpretation. Although a was observed within the reservoir zone acoustic logs and checkshot surveys from offset number of factors—such as washouts, formation (above). This drop might have signaled an wells.20 Next, they conduct a velocity volume analy- fluid type and anisotropy—can influence log impending roof or base exit from the targeted sis, computing normal compaction trends (NCTs) response, in general, these tools respond to section, or it might have indicated that the bit and creating pore pressure and wellbore stability changes in rock porosity. was entering the water leg of the reservoir. models. Leakoff test data from offset wells provide When PreVue engineers observe a porosity However, fluid facies analysis performed in control points for modeling the fracture gradient. increase as depth increases, they immediately real time showed that the fluid remained These models help the PreVue pressure engineers notify the driller and company representative. unchanged, indicating that the wellbore had identify potential zones of abnormal pressure, Quick detection of influx and changing gas con- not exited the oil zone. The resistivity decrease determine kick tolerances, develop mud weight tent is a critical task for the PreVue engineer. was attributed to increasing irreducible water windows and project where casing points should A typical response would be to increase mud saturation within the oil zone. be set (next page). weight until the influx is under control. However, PreVue real-time geopressure service—The Once drilling commences, PreVue wellsite this strategy is not without risk, such as uninten- PreVue services provide prespud pressure predic- pressure engineers closely monitor ROP and gas tional fracturing of the formation that can result tion along with wellsite monitoring of pore pres- readings as well as LWD and MWD logs; they in sudden mud loss. Increasing the mud weight sure and wellbore stability. Far in advance of rig update pressure plots, revise trend lines and watch may create new fractures or open existing frac- mobilization, pressure specialists collect data for variations from the predrill model. Using this tures and force mud into the formation. In per- from nearby offset wells and seismic surveys. information, they can apprise the wellsite com- meable formations, this can lead to fluid loss. They analyze well logs, pressure tests and mud pany representative of impending problems. Apart from the cost of losing expensive drilling reports to create a vertical stress model of each As drilling proceeds, LWD provides important fluid, significant mud loss from the annulus can wellbore, then correlate velocity and log response data for interpreting changes in pressure lead to lower hydrostatic pressure and result in a to wellbore pressure anomalies. difficult well control situation.
20. Following normal compaction trends, seismic interval Ismail Z, Azian Bt A Aziz I, Umar L, Azree B Nordin N, Harrold T and Raikes S: “Well-Positioned Seismic velocities increase with depth. Decreases in velocity Nesan TP, Rodriguez FR, Zapata FG, Garcia G, Waguih A, Measurements,” Oilfield Review 14, no. 1 with depth may be used to identify potential zones of Subroto B and Dow B: “Automated Managed Pressure (Spring 2002): 32–45. abnormal formation pressure. Drilling Allows Identification of New Reserves in a Arroyo JL, Breton P, Dijkerman H, Dingwall S, Guerra R, 21. Umar L, Azian I, Azree N, Ali ARM, Waguih A, Rojas F, HPHT Exploration Well in SB Field, Offshore Malaysia,” Hope R, Hornby B, Williams M, Jimenez RR, Lastennet T, Fey S, Subroto B, Dow B and Garcia G: “Demonstrating Paper IADC/SPE 151518, presented at the IADC/SPE Tulett J, Leaney S, Lim TK, Menkiti H, Puech J-C, the Value of Integrating FPWD Measurements with Drilling Conference and Exhibition, San Diego, California, Tcherkashnev S, Ter Burg T and Verliac M: “Superior Managed Pressure Drilling to Safely Drill Narrow March 6–8, 2012. Seismic Data from the Borehole,” Oilfield Review 15, Mud Weight Windows in HP/HT Environment,” paper 22. For more on look-ahead VSP methods: Borland W, no. 1 (Spring 2003): 2–23. SPE/IADC 156888, presented at the SPE/IADC Codazzi D, Hsu K, Rasmus J, Einchcomb C, Hashem M, Blackburn J, Daniels H, Dingwall S, Hampden-Smith G, Managed Pressure Drilling and Underbalanced Hewett V, Jackson M, Meehan R and Tweedy M: Leaney S, Le Calvez J, Nutt L, Menkiti H, Sanchez A Operations Conference and Exhibition, Milan, Italy, “Real-Time Answers to Well Drilling and Design and Schinelli M: “Borehole Seismic Surveys: Beyond March 20–21, 2012. Questions,” Oilfield Review 9, no. 2 (Summer 1997): 2–15. the Vertical Profile,” Oilfield Review 19, no. 3 Breton P, Crepin S, Perrin J-C, Esmersoy C, Hawthorn A, (Autumn 2007): 20–35. Meehan R, Underhill W, Frignet B, Haldorsen J,
38 Oilfield Review Turning on mud pumps raises the pressure of Drilling progress toward the pore pressure mic velocity. Both cases indicated that the range the mud, and this phenomenon can be regarded ramp was tracked by integrating LWD resistivity for increase in pore pressure gradient was around as a virtual increase in the mud density. logs and d-exponent plots, along with emphasis 1 lbm/galUS. This gave the drilling team a clearer Management of this gap between the effective on gas measurements and trends. Prior to drilling picture of what lay ahead and reinforced confi- static density (pumps off) and effective circulat- into the pressure transition zone, the operator dence in the computed model. ing density (pumps on) and its relationship to the ran a zero-offset VSP to update previous esti- The interval between intermediate casing formation pressure and rock strength is a key to mates of pore pressure. Based on this VSP data, and TD in the SBD-2 well was drilled in two successful drilling. The objective of the PreVue high- and low-pressure cases were developed sections. The first of these was drilled using a service is to balance the mud density—both with the same normal compaction trend line 10½-in. bit and a 12¼-in. underreamer. After 5 static and circulating—between the formation used to generate pore pressure curves from seis- 9 /8-in. casing was set, the second section was pressure and the rock strength. In 2011, Petronas Carigali Sdn Bhd drilled the high-pressure, high-temperature SBD-2 well, in the Malay basin offshore Malaysia. Based on pre- Kick Tolerance vious experience in the area, drillers expected 023ppg that they would have to contend with a narrow Fracture Gradient mud weight window constrained by pore pressure 023ppg and fracture pressure.21 An earlier offset well, the Normal Compaction Trend Pore Pressure SBD-1, experienced pressure problems accompa- 0.2ohm.m 20 023ppg nied by heavy mud losses, which prevented the Pore Pressure Indicator Overburden Gradient well from reaching its objective. 0.2ohm.m 20 023ppg Resistivity Normal Hydrostatic Gradient Using logs from the SBD-1 well, Petronas Depth, ft 0.2ohm.m 20 023ppg geologists were able to identify the onset of abnormal pore pressure. Before spudding the Casing SBD-2 well, Petronas wanted to determine the 1,000 depth of the transition from a lower pressure gra- Casing 2,000 Leakoff dient to a higher pressure gradient. PreVue pres- test sure specialists analyzed seismic data to 3,000 ascertain the top and base of this pressure ramp. A 3D seismic volume of the area was analyzed and 4,000 the velocity data from offset wells were extracted and compared with wireline and LWD data. These 5,000 data were used to compute overburden gradients and normal compaction trends in offset wells, 6,000 which were then integrated into a velocity model across the prospect location. Velocity values from 7,000 the prospect location and other sites were ana- 8,000 lyzed to determine the depth at onset of abnor- Casing Leakoff mal pressure and the magnitude of pressure. The test difference between pore pressure and kick toler- 9,000 ance left the driller with an extremely narrow Casing Leakoff equivalent mud weight window of just 1 to 10,000 test 1.5 lbm/galUS [0.12 to 0.18 g/cm3]. 11,000 During subsequent planning sessions, the operator elected to obtain borehole vertical seis- 12,000 mic profile (VSP) data after each casing run. This intermediate VSP data from the wellbore could be obtained in the relatively safe environment of the > Predrill analysis of an offset well log. Overpressured zones or intervals of inhibited compaction are SBD-2 cased hole. Moreover, it would allow the characterized by increased porosity, which can be identified through log responses from nearby offset project team to make time-depth conversions in wells. Pore pressure indicators (red dots, Track 1) are based on average shale resistivity (black) and their original model, which relied on surface seis- help to establish a normal pore compaction trend line (green). Deviations from the normal compaction trend may indicate abnormal pressure. PreVue pore pressure studies evaluate seismic data and logs, mic data. The VSP data would also allow the opera- leakoff tests and mud reports from offset wells to predict the onset of abnormal pressure, its tor to identify any changes in the model and could magnitude and the range of mud weights that can be used to control it. In this example, deviations be used as a tool for gauging the pore pressure from the normal compaction trend start at about 8,800 ft. The equivalent mud weight curves (Track 2) display a corresponding pressure behavior. Kick tolerance (light blue) is dictated by the weakest profile ahead of the bit. This valuable look-ahead formation exposed in open hole. The fracture gradient (dark blue), pore pressure (green), overburden information would guide the drilling team’s strat- gradient (red) and normal hydrostatic gradient (black) have been calculated to establish an allowable egy for drilling the well to its target.22 mud weight window (hatched) bounded by the kick tolerance and pore pressure curves.
Spring 2012 39 drilled to TD using an 8½-in. bit and a 9½-in. under- estimated pore pressure profile and ECDs were PreVue engineers also used gas measure- reamer. The underreamers increased the annular maintained close to the fracture gradient. Any pres- ments to obtain accurate indications of mud bal- volume, which reduced circulating pressures in the sure increase in which downhole ECD exceeded ance. As the well neared TD, gas peaks were annulus and lowered the ECD, thus counteracting kick tolerance resulted in seepage losses and thus observed following pump stoppages. PreVue engi- the effects of the heavy muds. Throughout this inter- gave the drilling team a reliable indicator for main- neers analyzed these gas increases and found val, the mud weight was maintained close to the taining downhole pressures. that, instead of a troublesome influx resulting from low mud weight, these gas peaks were caused by well breathing. Normal Hydrostatic Gradient Well breathing may be observed in some wells 8 ppg 23 following brief stoppages of the mud pump. When Interval Velocity Pore Pressure Gradient, Low-Pressure Case mud weight approaches the equivalent of the 8 ppg 23 fracture gradient, small fractures can develop in Pore Pressure Gradient from Deep Resistivity weak formations or along the interface between 8 ppg 23 Interval Velocity Pore Pressure Gradient, High-Pressure Case rock layers. While mud pumps are turned on, the 8 ppg 23 fractures may open, allowing drilling fluid to Mud Weight In enter. Light gases diffuse from the formation into 8 ppg 23 the drilling fluid. When the pumps are turned off Equivalent Circulating Density briefly, such as during a pipe connection, the 8 ppg 23 fractures slowly close, forcing the mud with Interval Velocity Fracture Gradient, Low-Pressure Case gas to flow back into the hole. When the drilling 8 ppg 23 fluid circulates to the surface, it registers as an Fracture Gradient from Deep Resistivity 8 ppg 23 increase in total gas. However, on the chromato- Interval Velocity Fracture Gradient, High-Pressure Case graph, it is characterized by an increase in C1 and 8 ppg 23 C2 gases, with little change in C3, C4 and C5 gases. Depth, Overburden Gradient Average To maintain mud weight within the narrow m 8 ppg 23 pressure window, managed pressure drilling (MPD) techniques were used for early kick detec- X,100 tion, maintaining constant bottomhole pressure X,200 control and conducting dynamic flow checks and dynamic formation integrity tests (FITs).23 When X,300 engineers compared the VSP look-ahead pore X,400 pressure curves with actual pressure readings X,500 from an MDT modular formation dynamics tester and StethoScope formation pressure-while-drill- X,600 ing tool, they found that the readings closely X,700 matched each other (left). After TD was reached, the wellbore was displaced with kill mud and the X,800 well was completed successfully. X,900 Thema drilling operations support and anal-
3 ysis service—The Thema service processes real- Y,000 13 /8-in. shoe LOT time, high-frequency data streams from a number Y,100 FIT of sensors around the rig to provide up-to-date
3 Y,200 11 /4-in. liner LOT analysis of hole condition, drilling efficiency, well Mud gain FIT pressure balance and rig performance. This infor- Y,300 5 bbl mation is displayed on customizable screens 5 Mud gain Y,400 9 /8-in. shoe installed at the logging unit and the company rep- 1.9 bbl Mud losses LOT Y,500 resentative’s workspace; it can also be accessed remotely from the operator’s offices. Y,600 Dynamic FIT In hole condition mode, Thema engineers Y,700 Mud losses analyze wellbore stability and hole cleaning effi- Mud losses Dynamic FIT ciency in real time. The drillstring weight is recorded while it is static, rotating or reciprocat- Casing depth Kick or flow MDT or StethoScope pressures Leakoff test Lost circulation zones ing. This program can also process input from > Final composite log. Look-ahead estimates of pore pressure from VSP analyses are confirmed by cuttings flowmeters. Data are presented in depth actual pressure readings from MDT and StethoScope tools. Mud weight was kept as low as possible or time, enabling the user to rapidly establish a to keep the ECD from exceeding the fracture strength of the rock. In spite of this effort, some mud losses were experienced. The plots show that mud pressures (red) were maintained close to the sequence and correlation between events. These estimated pore pressures.
40 Oilfield Review 1.0
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00:02 00:06 00:10 00:14 00:18 01:00 01:04 01:08 01:12 Time, min:s > Heave versus compensation. Using Thema service data, Geoservices personnel tracked a drillstring vibration problem on a well in the Campos basin off the coast of Brazil. A comparison between the magnitude of heave and compensation (left) showed deficiency in heave damping, which was subsequently corrected (right). data are analyzed to derive industry-standard val- To monitor rig performance, the Thema Analysis of sensor data helped Geoservices ues for torque, ECD, pickup, slack-off and free- service automatically tracks and displays a personnel track the problem to its root cause: rotating weights. specific combination of parameters, such as Drilling energy was being dissipated through The drilling efficiency mode evaluates vari- connection time or net drilling time per stand. shock and torsional resistance as a result of ous drilling parameters to assess bit behavior The duration of each activity is logged, heave motion (above). As is typical of semisub- and wear. Surface sensors monitor the fre- enabling assessment of the rig performance mersibles, the rig used heave compensators to quency and magnitude of axial vibration caused during various operations such as drilling, slid- reduce vertical drillstring movement caused by by bit bouncing and stick-slip torsional vibra- ing, tripping and circulating. The wellsite data the rise and fall of ocean waves. tions. These inputs are used to anticipate poten- specialists work with Thema engineers at the By fine-tuning the damping motion of the tial problems such as bit balling, drillstring operator’s office to provide timely updates to heave compensator, the drilling contractor was vibration and bit wear to optimize drilling rig site and office project members. able to mitigate the problem and boost ROP parameters. The drilling efficiency mode may The Thema service was recently called on to while reducing stress on the drillstring. The ROP help improve ROP and increase the life of down- determine the cause of poor drilling rates in increased from 16 m/h to 45 m/h [148 ft/h]— hole and surface equipment. wells off the coast of Brazil. During a three-year exceeding the 40-m/h average of neighboring The Thema service helped one operator in the drilling campaign, the operator utilized wells by more than 10%. These results prompted Middle East enhance core recovery in a forma- Geoservices mud logging and Thema services on the operator to implement the same monitoring tion susceptible to breakage. Breaks in core several wells drilled from semisubmersible rigs in and mitigation practices on the five rigs the com- cause two main problems. First, the operator has the Campos basin. While most of these wells were pany employed in the area. In light of these difficulty in recovering representative samples of drilled and completed on schedule, a few were results, the operator plans to use the Thema ser- the formation. Second, broken core causes gaps taking longer than expected to reach TD, owing vice in future wells. in the core recovery footage count, which can to dramatic decreases in ROP. The scope of services offered by mud logging severely degrade the quality of interpretation of In contrast to neighboring wells with ROPs companies continues to expand as new sensors any core that is eventually recovered. averaging 40 m/h [130 ft/h], some wells attained and analytical tools are developed. In response, Analysis of drilling sensor data from the first only 16 m/h [52 ft/h]—a 60% reduction. An eval- the mud logger has taken on an important role in coring run revealed the core was being sub- uation of drilling performance indicated that providing the operator and drilling crew with jected to severe torsional vibrations inside the ROP was hampered by vibration. However, the information that is crucial to the success of the core barrel, resulting in a poor-quality core with driller was unable to identify the exact cause of well and to the safety of the rig. In addition to many breaks and fractures. During a subsequent the problem. formation evaluation experts, the mud logging coring operation, the Thema service was used to On one well, the Thema service was used to unit must now accommodate specialists who are manage drilling parameters and minimize drill- record responses of various drilling perfor- responsible for drilling efficiency and well safety. string vibration. The operator obtained a clean, mance sensors located around the rig. The By linking a wide array of surface sensors to rapid unbroken core, thus validating the Thema anal- Thema system acquires data at up to 50 Hz, analytical capabilities and operational expertise, ysis and recommendations. enabling rapid correlation of sensor responses the mud logging unit is fast becoming the nerve to various drilling parameters. Among the center of the drilling rig. —MV 23. For more on managed pressure drilling: Elliott D, Montilva J, Francis P, Reitsma D, Shelton J and Roes V: inputs were data from sensors to detect motion “Managed Pressure Drilling Erases the Lines,” on the riser tensioner, heave compensator and Oilfield Review 23, no. 1 (Spring 2011): 14–23. topdrive block.
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