Status of Drill-Stem Testing Techniques and Analysis

H. K. VAN POOLLEN THE OHIO OIL CO. MEMBER AIME LITTLETON, OHIO

Abstract if the theoretical PI is low; but if the theoretical PI is Downloaded from http://onepetro.org/JPT/article-pdf/13/04/333/2237597/spe-1647-g-pa.pdf by guest on 28 September 2021 high, chances for stimulating the well are still good (either This paper is a compilation of the latest drill-stem testing 2 4 by removal of the skin surrounding the wellbore - or by techniques. New tools are described, together with present­ further penetration of the productive zone) . day interpretation techniques, and their limitations are given. The importance of proper times for shut-in and The reservoir pressure aids reservoir engineers in their flow periods are stressed. A number of suggestions for the reserve calculations. It is important in exploration studies future are given, and a rather complete list of references dealing with entrapment of oil under hydrodynamic con­ in the field of drill-stem testing has been supplied for use ditions. by interested readers. Trends in Drill-Stem Testing With more and more emphasis on detailed interpretation, Introduction the trend in drill-stem testing has been toward: (1) the use A drill-stem test (DST) is a temporary completion. It of double closed-in pressure tests;* (2) more accurate consists of a combination of a packer arrangement and pressure recording devices; (3) more accurate and detailed drill pipe or tubing. Valves are present in this arrange­ reading of pressure charts; (4) on-the-spot pressure eval­ ment to open and close the tool, and pressure and temp­ uation of tests and calculations; (5) calculations by means erature recording devices are employed. Upon completion of digital computers; and (6) new tools enabling up-hole of the test, the entire arrangement is withdrawn from the testing, continuous testing and testing while drilling. well. The purpose of a DST is (1) to determine whether or Basic Tools not to complete the well and (2) to obtain reservoir or Drill-stem testing can be divided into two main cate­ aquifer information for exploration applications. The DST gories - open-hole and hook-wall. Since the operating and will render a wealth of information - e.g., a sample of mechanical principles of the two strings of tools are the the fluid itself, the actual productivity index, the reservoir same, only the open-hole string will be discussed. pressure, the theoretical productivity index and the amount Trends in modern drill-stem testing have led to more of well bore damage. versatile and, consequently, more complete tools.'-1O The The fluid will show whether the well can be completed various components that make up a test string can be as­ as an oil well, a condensate well or a gas well; or, it will sembled in any number of combinations. Only the parts of show if the formation should be abandoned (for being a the string considered most important for interpretation will water producer or for being dry). Tests can be run on the be discussed (Fig. 1). sample to determine the hydrocarbons present, viscosity Starting at the bottom of the string, the most commori of the mixture, API gravity, paraffin content, pour point testing tools and their main function are as follows: or gas-oil ratio. The water produced can be analyzed for salinity and electrolytes present to aid in stratigraphic The blanked-off pressure recorder (outside gauge) pro­ correlation, and the resistivity of the water will aid the vides a step-by-step graphic story of the drill-stem test. By logging engineer in his evaluation of the electric logs. The comparison with other gauges in the string, it will reveal DST further aids in determining gas-oil or oil-water con­ the proper function of the testing string. No flow of fluids tacts, and the proximity of pinchouts or faults. from the formation passes by this gauge; consequently, all pressures are recorded directly from the annulus below Two different productivity indices (PI) can be obtained the packer. during the DST - (1) the actual PI and (2) the theoreti­ cal PI. Normally, the actual PI is lower than the theoretical The perforated anchor supports the testing string and PI. A high actual PI shown by a given well probably will keeps the packer seated in the well bore. The anchor is be the deciding factor in favor of completing that well. provided with small holes (approximately 3/16 in.) to If the actual PI is low, however, the well possibly should allow passage of formation fluids and to screen debris that be abandoned. In all probability, it should be abandoned might otherwise plug the fluid passages in the tool. 2References given at end of paper. Original manuscript received in Society of Petroleum Engineers office ~'Where air chambers originally were used for the determination of Nov. 22. 1960. Revised manuscript received Feb. 23. 1961. Paper presented initial closed-in pressures, present-day practice trends toward the method at 5PE Formation Evalu.. tion Symposium. Nov. 21·22. 1960. in Houston. of initial flow followed by initial shut-in.

APRIL, 1961 SPE 1647-G Reprinted from the Aprii. 1961. Is.ue of JOUR:--lAL OF PETROLEUM TECH:--lOLOGY 333 The packer assembly provides a bridge in the well bore Then it is shut in to record the initial closed-in pressure. between the drilling fluid and the zone to be tested. The The initial flow and shut-in periods also may be estab­ hydrostatic head is withheld from the formation by means lished by means of a conventional tester valve. After the of the packer. packer is set, the by-pass closes and the tester valve opens. The flow-stream gauge (inside gauge.) also will give a This is the beginning of the initial flow period. To shut-in concise picture of the testing operation. This pressure the well, the pipe is lifted enough to close the tester valve recorder is placed in the flow stream above the packer and but not enough to unseat the packer. A special arrange­ below the tester valve. All pressure fluctuations must pass ment keeps the by-pass from opening." through the perforated anchor to reach this recorder. Important optional components of a testing string are The tester valve prevents entry of drilling fluids into the safety joints, jars, bottom-hole choke, reversing sub, etc. empty drill pipe while the pipe is being run into the hole. (Local conditions will govern location of the tools in the It also retains a sample of the formation fluids recovered string and their application.) while pulling out of the hole. Several improvements on the tester valve have been offered the industry in recent Testing Without Use of Anchor Pipe years. The air-chamber gauge generally is run inside the air It is frequently desired to test only a certain part of a chamber on tests where an initial closed-in pressure is formation. In this case, two packer arrangements are used taken and provides a means of checking the air chamber in such a manner that they "straddle" the zone of interest. The anchor pipe is blanked off. The lower packer separates for fluid entry prior to the opening of the tester valve. Downloaded from http://onepetro.org/JPT/article-pdf/13/04/333/2237597/spe-1647-g-pa.pdf by guest on 28 September 2021 the bottom of the hole from the formation, and the upper An auxiliary valve placed at a distance above the tester packer separates the formation from the annular space valve provides an air chamber into which compressed mud above the upper packer. In straddle-packer testing, long below the packer can expand when the tester valve is anchor pipes frequently are used, extending from the zone opened. This method allows the pressure beneath the of interest to total depth. packer to drop below reservoir pressure, followed by a It is possible now to perform straddle tests without the rapid build-up of the formation pressure prior to any use of anchor pipe.",5l The tool which replaces the anchor appreciable amount of production. pipe consists of mechanical slips mounted on a wedge­ Two types of auxiliary valves are available for the dual shaped body, a set of open-hole type drag springs, and a closed-in pressure procedure." One is the disc valve, which J-slot locking mechanism to hold the slips in the unset consists of a steel body with a fluid passage blanked-off by position while going into the hole. To set the tool, the drill an aluminum disc. This type of valve is opened by dropping stem is picked up slightly, rotated and lowered, releasing a steel bar to rupture the disc. Another valve is a rotation the J-slot locking mechanism and allowing the slips to type which has a three-position sleeve. The valve is run expand. After the slips are set against the wall of the hole, into the hole in the closed position and is opened by they provide support for the drill-pipe weight that must rotation. Further rotation will again close the valve and be applied to set the packers and open the tester valve. To provide a final closed-in pressure. release the slips, the drill stem is picked up, which reposi­ Also available to the industry is another rotation-type tions the locking mechanism and readies the tool for re­ auxiliary valve!"" This newer type of auxiliary valve offers setting. two advantages over the other equipment. It eliminates the additional piece of equipment necessary to reverse out the Testing Procedures recovery obtained on the DST, and the air-chamber is DST's can he classified as (1) conventional, (2) double eliminated. This valve is opened to flow for a period just closed-in using air chambers and (3) double closed-in long enough to bleed-off the pressure below the packer. with a flow period preceding each shut-in. Conventional DST

DRILL PIPE -----i4-~I The conventional DST consists of four periods (Fig. 2) - (1) going in the hole, (2) flow into tool, (3) shut-in AUXILIARY VALVE------',* ..u. ANDIOR , period, and (4) coming out of the hole. Detailed chart CIRCULATING VALVE ~L descriptions have been treated adequately in the litera­ AIR CHAMBER GAUGE I ture.",I2,52 (OPTIONALl ~ The increase in pressure during Period 1 is caused by TESTER VALVE AND --:.:>+. BY - PASS VALVE ~ ~ the weight of the mud column. When the packer is set and the tester valve is opened, this weight is removed and ~ ACE J FLOW - STREAM GAUGE--i - -F---- replaced by the weight of the column in the drill pipe, being - - - ~------either air or a cushion. The increase in pressure during -.... -- - -- . , G OPTIONAL TOOLS --~~. Period 2 results from the increasing weight of fluid flowing / - -- (JARS,SAFETY JOINT / into the drill pipe. At the end of this period, a valve is AND ETC.) / __ B 0 __H_ ,/ closed at the tool and further increase in pressure results I I I from the restoration of formation pressure. Next, the I / I packer is released and mud pressure takes over, which de­ / / creases again during Period 4 when the tool is run out PACKER ASSEMBLY ---,-:_ I I I of the hole. I / -./ Double Closed-in DST Using Air Chamber PERFORATED ANCHOR~ 1:;" The principle of measuring the initial shut-in pressure BLANKED-OFF GAUGE is to produce a very small amount of fluid from the forma­ ~\.~ .. J tion followed by a shut-in period long enough to allow for pressure equalization. The pressure measured after this Fig. I-The main components of a typical drill-stem testing string. shut-in period is the "true" reservoir pressure.

334 JOURNAL OF PETROLEUM TECHNOLOGY ~ \J----\t----~- 1 TIME--- T1ME- TIME­ 0:: a b C :::> (J) (J) W 0:: a.. I , \P---\}---\d---- TIME- TIME-+­ TlME_ d e f

Fig. 3-Examples of initial shut-in pressures obtained Downloaded from http://onepetro.org/JPT/article-pdf/13/04/333/2237597/spe-1647-g-pa.pdf by guest on 28 September 2021 -TIME- by means of an air chamber.

Fi~. 2-Demonstration of important pm·ts of pressure charts and water "ushion: (l) going into hole, (2) flow into tool, (3) shut-in period, and (4) coming out of hole. shut-in pressure should not become static within 10 minutes for a 12-hour clock, 20 minutes for a 24-hour clock, 40 minutes for a 48-hour clock, or 60 minutes for a 72-hour At first (and still at the present), an air chamber was clock. incorporated in the conventional testing string. The air Figs. 3d and 3e are initial shut-in pressure curves using chamber is the volume inside the testing string between the an air chamber which is too large for the prevailing con­ tester valve and an auxiliary valve. Fig. 1 shows the rela­ ditions. In this case, the reservoir pressure has not been tive location of the valves and the resulting pressure charts. reached. Fig. 3f is another example of an air chamber When the packer is set and the tester valve is opened, which is too small for the conditions. Notice how the pres­ the mud which was trapped below the packer is allowed sure bled off into the formation and approached reservoir to expand into the air chamber. The flow will stop as soon pressure. as the air chamber becomes filled with both the mud and the formation fluid. The pressure will build up, and within Double Closed-in DST Using Two Flow Periods a short time it will be very close to the original reservoir Although the air chamber is still used exclusively in pressure. After the initial shut-in pressure has been taken, certain areas, the many disadvantages of this method led the auxiliary valve is opened and the test continued as if to the use of the method based on two flow periods. The it were a conventional DST. principle is the same; that is, prior to measuring the reser­ The air-chamber method of measuring initial shut-in voir, the pressure below the packer is reduced to just a pressure has limitations. To obtain a correct initial shut-in little less than the reservoir pressure. This now is accom­ pressure representative of the reservoir pressure, the air plished by opening the tool to flow for a short period, after chamber should be calculated precisely. A reasonably ac­ which the tool is shut in. The tool then is opened for flow, curate measurement of the borehole diameter is required. and the rest of the test is conducted in the conventional The compressibility of the mud should be known, and some manner. idea should exist concerning the order of magnitude of the The advantages of this method are that guesswork is reservoir pressure. Also, the hole should be very clean. The eliminated and that, if necessary, the reservoir pressure may bottom section of the hole may be partially filled with be calculated from both the initial and final shut-in. One cavings or cuttings which will not carry the load of the should keep in mind, however, that it is preferable to testing string (false bottom), resulting in sliding of the measure the reservoir pressure rather than to calculate it. packer and the air chamber's becoming relatively too small. Fig. 4 is an example of a two-flow-period test. Although When using an air chamber to obtain an initial shut-in the initial shut-in pressure curve appears fairly flat, the pressure, it is wise to clean the hole thoroughly and to initial pressure is still less than the final shut-in pressure. rely on the experience of the tester in any particular area. Had the initial flow been shorter, a more complete initial It next becomes important to evaluate the validity of shut-in pressure would have resulted. measured initial shut-in pressure. Fig. 3 illustrates a number of examples of initial shut-in Water and Gas Cushions pressures obtained by means of an air chamber. Fig. 3a demonstrates a perfect measurement. A definite curvature A water cushion consists of a column of water above in the beginning may be noticed, making it definitely differ­ the testing tool inside the drill stem. When high pressures ent from Fig. 3c. It demonstrates how the pressure below with high productivity is expected, the cushion will slow the packer was released and a build-up of reservoir pressure down the initial rate of flow. It decreases the possibility of followed, ending with a flat portion. Fig. 3b is also a good pulling in the formation because of the sudden drop in measurement; however, it may be difficult to distinguish it pressure. It reduces the possibility of forming a gas block from Fig. 3c because of the small amount of curvature. In in tight formations. Therefore, it may be possible that a this case, the air chamber was somewhat small for the greater recovery is obtained with the use of a cushion. It prevailing conditions. Another reason may be the speed of prevents collapsing of the testing string in very deep wells the clock used in this test. To see the curvature, the initial or where the mud is extremely heavy.

APRIL, 1961 335 sampler chamber and one outside the ehamber below the testing valve. Fig. 5 shows examples of the pressure charts. The blanked-off gauge records hydrostatic mud pressure as the sampler is lowered inside the drill pipe (A-B), pres­ sure changes in the test interval during the sampling period independent of fluid flow (C-D), final hydrcstatic pressure of the mud column (E), and returning out of the hole (E-F) . This tool has its greatest advantage when used in con­ junction with straddle packers without anchor pipc. Many zones can be tested and sampled during a single trip of the drill stem. The tool enables the narrow location of the water-oil cr oil-gas contacts by setting the tool at different depths within a zone. In a similar manner, one may be able to determine the permeability profile within a zone. TIME • Limitations are the size of the sampling chamber and Fi.g. 4-Douhle shut-in pressure using two flow periods. the lack of an easy interpretation method. By knowing the Initial closed-in pressure = 1,518 psi; final size of the sampler chamber and by determining the com­ shut-in pressure = 1,520 psi. pressibility of the fluids produced, one should be able to Downloaded from http://onepetro.org/JPT/article-pdf/13/04/333/2237597/spe-1647-g-pa.pdf by guest on 28 September 2021 calculate certain reservoir parameters and wellbore damage. A disadvantage of a water cushion may be that a low­ However, no method is presently available whereby such pressure reservoir could be undetected due to the inability analyses can be made in field offices. Besides a qualitative to record pressure data or recover a sample. One service value for prcductive capacity, the reservoir data is limited offers a back-pressure valve which supports the water at present to the equalized reservoir pressure. cushion and provides an air space between the water cushion and the testing tool!5 The valve is run on top of Testing While Drilling the drill collars, and the air space provides a means for A special formation evaluation tool" is available now recovering a sample and pressure data even if the forma­ which makes it possible to sample zones encountered while tion pressure is less than the water-cushion pressure. If the drilling, without the necessity of round trips. The principle formation pressure is higher than the water-cushion pres­ of the test is quite similar to the method of multiple-zone sure, the valve will open and allow the formation to sampling described in the previous section. Again, there are produce. two assemblies - the packer assembly and the sampler. Both natural gas and nitrogen under pressure have been The packer assembly is made up as part of the drilling used as a cushion. Originally, the entire drill stem was string and contains an inflation-type packer. The sampler pressured up. In some areas, use is made of bottled nitro­ is retrievable, similar to the one described in the previous gen.IT, .. "., .. One of the later developments in the use of gas section. cushions is a valve which is installed on top of the cushion. Sampling the formation is done with the bit on bottom, The valve, set to maintain enough pressure to prevent the the sampled interval being 3 to 4 ft. The manipulation of drill pipe from collapsing, eliminates the need for filling valves and setting of the packers is accomplished by rais- the entire string with nitrogen. When the fluid pressure of the formation rises above the pressure set on the valve, the valve opens, allowing formation fluids to flow into the pipe. The speed by which the pipe can be filled with nitrogen as compared to a fluid cushion is an advantage. The fact that nitrogen is practically inert makes it possible to obtain uncontaminated formation fluid samples. It further de­ creases the possibility of damaging the formation in the case of low pressures. With the use of gas cushions, it is possible to alternately increase or decrease the pressure on the cushion in an attempt to remove temporary well bore damage.

Multiple-Zone Sampling A recently developed tool46 makes it possible to obtain formation fluid samples and shut-in pressures from several zones, or several sections of a single zone, with only one trip of the drill pipe.20 It consists of two assemblies - the conventional testing string, and the sampler which is run on a wire line and which can be retrieved for each test. Samples of up to 25 gal or more can be taken from test intervals as small as 1 ft. A straddle-packer arrangement is run on the drill stem to the desired zone and set. Next, a sampler is run inside Fig. 5-Charb obtaincd using mu!tiple-zonc sampler. A·B, the drill pipe. This arrangement permits withdrawal of running sampler in hole; B, initial hydrostatic mud pres­ sure; C, tester valve opencd; CoD, formation build-up; D, samples from the reservoir and the recording of pressures. tester valve closed; E, final hydrostatic pressure; E-F, re­ The sampler contains two pressure recorders, one in the trieving sampler; and F-G, releasing pressure at surface.

336 JOURNAL OF PETROLEUM TECHNOLOGY ing and lowering the pump pressun: without moving the en the test, the accuracy of the gauge during the particular drill pipe. The pressures applied on the drill pipe usually test can be estimated. Fig. 6 shows stair-stepping of a are on the order of 1,000 psi during the testing period. gauge. This is caused by the recorder's hanging up and is The advantage is that the formation may be tested im­ usually a result of poor maintenance. No accuracy should mediately following penetration by the bit without neces­ be expected if stair-stepping occurs. sitating a round trip of the drill pipe. The limitations are To obtain maximum accuracy, the proper-size gauge the same as for the multiple wireline sampler - the size and clock should be used for the test. The gauge size should of the sampling chamber and the lack of an easy interpre­ be approximately 125 per cent of the maximum reading tation method. expected. Also, the type of reading instrument may in­ fluence the accuracy of the final answer. Completion Testing Tool Interpretation During the last few years, a tool has been developed which makes it possible to treat and test the well with the The theery of pressure build-up interpretation and ex­ same tool. ",,23,43,53 The tool has a full-bore opening which trapolation has been covered extensively in the literature."-" permits almost any kind of workover. Any number of these Usually, the build-up pressures are plotted vs 10glO [( T + operations can be performed in any desired sequence, and 0) /0] where T is the time the tool was open to flow and no round trips are necessary. The testing is performed o is the time the tool was closed in during the final shut­ making use of a valve arrangement run on a wire line. in period. The best straight line is drawn through these Downloaded from http://onepetro.org/JPT/article-pdf/13/04/333/2237597/spe-1647-g-pa.pdf by guest on 28 September 2021 The packer is a multipurpose hook-wall type, and an points and is extended to intersect the line for which integral part is a circulating valve that can be locked in [( T + 0) /0] = 1. The pressure at this point of intersection either open or closed position. During squeezing, treating supposedly is equal to the aquifer pressure. The value and testing operations, the valve is locked closed and can should be the same as that of the measured initial shut-in be opened at any time to allow circulation above the pressure. The slope of the straight line obtained in this packer. Attached to the lower end of the valve is a pressure manner can be used to calculate the permeability of the gauge for testing purposes. formation and to estimate effects of well bore damage from To obtain a sample of the formation fluid, a swab is run the following equations. prior to retrieving the valve, or the fluid is reversed out q Kh (md-ft) = 162 6-- ( B/D ). (1) following retrieving of the valve. '" cp . slope psi/cycle ' Without the valve positioned in the tool, workovers can FC]P - FFP( psi ) be performed through the tool. Following a workover, the Damage Ratio = 0.183 . I ; formation can be tested again by running in the valve, slope pSI/cyc e swabbing dry above the valve, and continuing as usual. (2) or FClP - FFP Chemical Cleaner Damage Ratio = --;--=--c--=:-::-;:­ log T + 2.63 slope A tool which permits the chemical cleaning of a forma­ (3) tion prior to actual testing has been used." The purpose of where K = permeability (md), the chemical cleaning is to remove mud damage which otherwise might obscure the test. The tool consists of a h = formation thickness (ft), pump run immediately above the tester valve and operated p. = viscosity (cp), by application of the drill-pipe weight. q = flow rate (res B/D), FChJ = final closed-in pressure (psi), Pressure Recorders FFP = final flow pressure (psi), and Several types of pressure recorders are used in drill­ T = flow time (minutes). stem testing. The merit of one kind over another is a point The equations for damage ratio are only approximations, for argument. However, no gauge can maintain its accuracy but as such they should be considered very useful. The without due maintenance. By running more than one gauge value for the damage ratio is an indication of how much more the well could have produced if no "wellbore damage" were obstructing the flow into the well. Theoretically, a straight line will be obtained through the pressure points. In practice, however, this line frequent­ ly is curved. The curvature usually is more severe on low­ recovery wells. These wells either are located in low­ permeability reservoirs or have been damaged extensively. If the well is allowed to be left shut-in long ensugh, a straight-linc portion will result. The accuracy of the ex­ trapolated reservoir pressure is influenced strongly by the length of shut-in time." Similarly, the wreng slope may be l;ScJ to calculate the permeability and the damage ratio. If the damage ratio calculates to be less than 0.7, one may lVis~ to check the validity cf the slope used. Having both an initial and final shut-in pressure definitely is helpful in determining the correct slope of the plot. ~ TIME Suggested Times for Flow and Shut-in Periods Fig. 6-Stair-stepping of gauge. Obviously the proper times for flow and shut-in periods

APRIL, 1961 337 become rather important. The following rules-of-thumb may be helpful. 1. To obtain a representative value, use at least 30 min­ utes for measuring the initial closed-in pressure, prefer­ ably longer. This includes the time for the initial flow period if that method is used. If only less time can be allowed for the initial closed-in pressure, it is better to eliminate that measurement and use the time for other parts of the test. 2. If the initial flow method is used to obtain the initial shut-in pressure, this flow period should only be long enough to allow the mud below the packer to expand so that the mud pressure will be less than the formation pres­ sure. Such expansion occurs rather quickly and can be recognized when "bubbles" are noticed in the surface "bucket". The tool then should be closed as quickly as possible. Watch for any pipe movement which may result from the packer sliding down (in case of a false bottom

due to hole conditions). Downloaded from http://onepetro.org/JPT/article-pdf/13/04/333/2237597/spe-1647-g-pa.pdf by guest on 28 September 2021 3. The major consideration for time on bottom is hole condition. Subtract the time required to obtain the initial shut-in pressure from the total time allowed. This difference is equal to final flow time plus final shut-in time. The ratio of the flow time and final shut-in time is suggested to be as follows. In case of good recovery, make the shut-in time at least one-half the flow time. In case of poor recov­ .- TIME ery, make the shut-in at least twice the flowing time. (The Fig. 7-S-type curves: (a) mud leak, and (h) "afterflow". length of flow time may influence the evaluation of a DST. It is possible that the mud-filtrate invasion prior to testing is of such magnitude that the actual productive fluids are the reservoir pressure if one expects to use simple calcUla­ obscured on the test.") tions requirieg desk calculators only. As already indicated, the times used on DST's frequently S-Type Curve are insufficient to locate barriers. Similarly, only in Two kinds of S-type curves exist. One kind is due to rare instances can one determine the size of a small reser­ mud by-passing the packer through vertical permeability. voir. Several methods of pressure drawdown and build-up In that case, the extrapolated reservoir pressure should be analysis have been developed which permit barrier detection and allow the estimation of such reservoir paramenters. By close to the hydrostatic mud pressure. It will reach that point by the way of a curved line on the pressure-vs-Iog means of these methods, it further should be possible to locate gas-oil and gas-water contacts. The prime require­ [( T + 0) / OJ plot. The other kind is due to saturation variations. During the flow period, the drawdown is very ment becomes the length of time necessary. The time re­ high. As a result, gas will come out of solution and mayor quirements may be many hours of flow. Besides the rig may not form a temporary gas block. After the well is shut cost and the fear of packers becoming stuck, the well will in, the pressure gradually rises and the gas will go back frequently kill itself during such a period. Therefore, look­ into solution. As a result, some "after production" into the ing into the future, it might be advisable to have some sort gas-filled pores will take place. On poor producers, this of pump which is capable of pumping a well on a drill-stem after-production will be noticeable as a definite "S", where test at a constant rate of flow. This tool would be a major on good producers this effect occurs very quickly and is asset for the purpose of exploration. not too noticeable. Fig. 7a is an example of an S-type curve Present methods of interpretation are limited to wells as a result of mud leakage, and Fig. 7b is an example of producing at moderate rates of flow. No simple method is after-production. available for interpreting tests conducted on high-capacity wells which kill themselves during the test. Limitations of Present-Day Interpretation Techniques Application of Computers for DST Interpretation The routine interpretation methods used today make it Although the standard interpretation method outlined possible to calculate (1) reservoir pressure, (2) permea­ previously is simple enough for desk calculations, high­ bility, (3) wellbore damage, (4) well capacity and (5) speed digital computers have been used successfully." The location of an ideal linear barrier. The location of an ideal advantages of a mechanized system are threefold: (1) linear barrier has been discussed in the literature."'" It has large quantities of tests can be interpreted and made avail­ been the author's experience that such methods will be able for distribution; (2) a more complete evaluation and applicable in only a very few cases with the times used screening of tests can be effected; and (3) individual on today's DST's and only if the barrier is very close. human errors are eliminated. The methods described herein are only applicable to oil High-speed digital computers become even more valuable and/or water producers. With the drawdowns used today in those cases where routine desk-type calculations do not during the flowing period, these methods should be con­ suffice. sidered to be limited for gas wells to the determination of Analog computers also have been used for the purpose (1) reservoir pressure, and (2) open-flow capacity under of DST ihterpretation.38 Although the analog computer may DST conditions. To obtain valid information from gas be an excellent tool for DST research, it is too cumbersome wells, the drawdowns should be kept within 10 per cent of for DST interpretation and analysis.

338 JOURNAL OF PETROLEUM TECHNOLOGY DST Data Centers 16. "Mud Control Big Key to Drill Stem Test", Drilling (Dec., Several centers for the exchange of well information have 1954). been in existence for many years. Electrical and nuclear 17. Smith, A. W.: Pet. Eng. (May, 1959) B·37. well logs were made available to the industry in this man­ 18. Stormont, D. H.: Oil and Gas Jour. (Sept. 16, 1957) 122. ner. Only recently have centers",,40 been set up to handle 19. "Nitrogen: Growing Tool for Testing", Pet. Week (Feb. 7. 1958) 18. DST records. 20. Chisholm, P.: World Oil (May, 1960) 120. Future Possibilities 21. Hyde, W. E. : World Oil (Sept., 1959) 63. 22. Farley, D. L. and Schwegman, H. E.: Pet. Eng. (Jan., 1958) Today, excellent tools are available to perform DST's, B·69. but average DST procedure applied today does not fully 23. Farley, D. L.: "The Retrievable Valve Testing System Used in Well Evaluation and Completion Operations", Paper 1297-G utilize these tools. Much is still to be gained from proper presented at 34th Annual Fall Meeting of SPE in Dallas (Oct. timing and interpretation of each test with today's methods. 4·7, 1959). Nevertheless, new techniques could be helpful. In the fol­ 24. Lancaster, E. V., Schwegman, H. E. and Wright, W. H.: lowing paragraphs, a number of suggestions are made. Oil and Gas Jour. (March 10, 1958) 186. These suggestions do not all appear to be practical at this 25. Horner, D. R.: "Pressure Build-up in Wells", Proc., Third particular time, due to either technique or economics; World Pet. Congress (1951) Sec. II., E. J. Brill, Leiden, Holland. however, they may become feasible in the future. 26. Dolan, J. P., Einarsen, C. A. and Hill, G.. A.: Trans., AIME The subsurface pump, and the effect it may have on driIl­ (1957) 210, 318. stem test possibilities, was mentioned in the section on 27. Zak, A. J., Jr. and Griffin, P., III: Oil and Gas Jour. (May Downloaded from http://onepetro.org/JPT/article-pdf/13/04/333/2237597/spe-1647-g-pa.pdf by guest on 28 September 2021 limitations of interpretation methods. 13, 1957) 136. Surface recordings already are used on an experimental 28. Zak, A. J., Jr. and Griffin, P., III: Oil and Gas Jour. (May 27, 1957) 125. basis. By this means, the test can be monitored from the 29. Zak, A. J., Jr. and Griffin, P., III: Oil and Gas Jour. (April surface. The produced fluid and its rate could be deter­ 15, 1957) 122. mined while the tool is still in the hole, the information 30. Zak, A .., Jr. and Griffin, P., III: Oil and Gas Jour. (April could be interpreted during the test; making it possible to 29, 1957) 193. obtain proper shut-in times; and the information would be 31. G.riffin, P., III: "Field Evaluation of Drill Stem Tests", AIME transmitted to the surface sooner, allowing more time for paper presented at Calgary, Alta. (Nov. 14-15, 1957); and decision-making. The same advantages could be obtained bulletin of Johnston Testers, Inc. if today's recording instruments were made retrievable 32. Ammann, C. B.: Jour. Pet. Tech. (May, 1960) XII, No.5, 27. together with a sampler. 33. Borisov, Yu. P. and Mukharskii, E. D.: Neftyanoe Khoz (1960) 38, No.1, 56. ATS translation RJ·2337. Field chart-readers, capable of detailed pressure-chart 34. van Poollen, H. K.: World Oil (Nov., 1957) 138. readings, would be helpful with today's tools and gauges. 35. van Poollen, H. K. and Bateman, S. J.: World Oil (July, Presently, it takes at least 24 hours to obtain the data 1958) 90. necessary to evaluate a DST properly. 36. Grynberg, J.: Oil and Gas Jour. (June 22, 1959) 106. Pressure differential gauges will be helpful in detecting 37. Drill·Stem-Test Pressure Analysis, Report by Petroleum Re· very small pressure differences. Today, it takes O.OOl-in. search Corp., Denver. deflection on a 4,OOO-psi gauge to detect 1 psi. The pressure 38. Dolan, J. P. and Hill, G. A.: "Electric Analog Interpretation of Drill Stem Test Pressure Build·up Curves", Paper 497·G increases very slowly towards the end of a build-up curve, presented at First Annual Regional Meeting of AIME Rocky and interpretations would become more meaningful if more Mountain Petroleum Section in Denver (May 27, 1955). accurate readings could be obtained during this period - 39. Petroleum Research Corp., Denver. interpretation methods presently shelved possibly could 10. Murray DST Exchange, Billings, Mont. again become useful techniques. Brochures, Manuals, and Operational Procedures References Halliburton Co. 1. Black, W. M.: Jour. Pet. T'ech. (June, 1956) VIII, No.6, 21. 41. Dual Closed·in-Pressure. 2. van Everdingen, A. F.: Trans., AIME (1953) 198, 171. 42. Dual Closed·in·Pressure Valve. 3. Hurst, W.: Pet. Eng. (Oct., 1953) B·6. 43. Locked Open By·Pass for Modified Hydro·Spring Tester. 4. Jones, F. O. and Neil, J. D.: "The Effect of Clay Blocking 44. Off·Bottom Testing. and Low Permeability on Formation Testing", Paper 1515·G presented at 35th Annual Fall Meeting of SPE in Denver 45. Retrievable Back Pressure Valve for Water Cushion. (Oct. 2·5, 1960). 46. Multiple Zone Wire Line Sampler. 5. Nisle, R. G.: Trans., AIME (1958) 213,85. 47. CR (Continuous Retrievable) Sampler. 6. Brons, F. and Marting, V. E.: Jour. Pet. Tech. (Feb., 1961) 48. Restrievable Test-Treat-Squeeze Packer and Retrievable Valve VIII, No.2, 172. Tester. 7. Pitman, R. A. and Potter, A. R.: "DST in Canada", Current 49. Formation Testing Manual. Trends and Equipment (Aug. 20, 1956) 173. Johnston Testers 8. Liedholm, C. c.: Oil and Gas Jour. (Nov. 5, 1956) 1I3. 9. Bleakley, W. B.: Oil and Gas Jour. (Dec. 22, 1958) 58. 50. Four Stage Shut·in Tool. 10. Richardson, C. R.: Pet. Eng., Part A (Aug., 1960) B·36; Part 51. Selective Zone Testing. B (Sept., 1960) B·64. 52. The Interpretation of Drill Stem Test Data. 11. Olson, C. c.: World Oil (Feb., 1953) 155. 53. Full·Bore Test and Completion Tool. 12. Pierot, M.: "Anomalies des disgrammes de tests. Essai de 54. Practical Drill Stem Testing Manual. diagnostic", Rev. Inst. Francais du Petrole (May, 1955) 365. Cook Testing Co. 13. Hatfield, C. D.: Pet. Eng. (Oct., 1958) B·60. 14. Dixon, B. R.: World Oil (June, 1958) 191. 55. Cook Nitrogen Service. 15. Wilson, G. E. and Holmes, J. R.: "Proper Preparation for 56. Engineered Formation Testing Manual. *** Drill Stem Testing", API Paper 926·5·D, San Antonio, Tex. (March 17·18, 1960); and "Make Your Drill Stem Test a EDITOR'S NOTE: A PICTURE AND BIOGRAPHICAL SKETCH Success", Pet. Eng. (May, 1960) B·40. OF H. K. VAN POOLLEN APPEAR ON PAGE 363.

~PRIL. 1961