FEATURE ARTICLE

A REVIEW of DRILL-STEM TESTING TECHNIQUES and ANALYSIS

W. MARSHALL BLACK HUMBLE OIL & REFINING CO. JUNIOR MEMBER AIME HOUSTON, TEX. Downloaded from http://onepetro.org/JPT/article-pdf/8/06/21/2237729/spe-589-g.pdf by guest on 02 October 2021

Abstract ether-cuts may be used to detect hy­ tion evaluation. Presently, tests in­ drocarbon shows. side casing are about 91 per cent The present techniques of using mechanically successful as compared the drill-stem test as a formation 2. Test possibly productive inter­ with 81 per cent 10 years ago, and evaluation tool are discussed. The vals in open hole after drilling deep­ er or reaching total depth; normally, conventional open-hole, wall packer basic drill-stem test operation is di­ testing is mechanically successful vided for discussion into three phases: this method requires that a cement plug be set for each test, unless strad­ about 87 per cent of the time as planning the test, performing the test, compared with 72 per cent 10 years and interpretation, both qualitative dle packer testing is employed. Side­ ago. and quantitative. The use of small wall cores and logs are commonly bottom chokes and large top chokes used to detect the shows. The Drill-Stem Testing Tool is suggested in order to permit quan­ 3. Test possibly productive inter­ Modern drill-stem testing tools are titative interpretation for gas-oil ratio, vals through perforations after casing highly versatile and consequently are productivity, and permeability. The has been set; log and core data may complex. The various components importance of measuring chloride be used in selecting the intervals. may be assembled in innumerable content on a suite of samples taken Drill-stem testing is widely used to combinations, either to provide spe­ from a recovered column of salt wa­ confirm or prove the presence and! or cial information or to provide for ter is illustrated. the producibility of oil and gas that emergencies that may develop. The is detected by the other services. The following paragraphs briefly outline Introduction testing program in a well can follow the functions of the more common anyone of the methods of drill-stem tool components. A drill-stem test is a temporary testing outlined in the preceding sec­ The three basic mechanisms or completion of the well. Drill-stem tion; however, the method of testing components of a drill-stem test tool tests are usually made for one or cored shows as the prospective pays are as follows: (1) the tester valve, both of the following reasons: ( 1) are penetrated is probably most wide­ (2) the by-pass valve, and (3) the to determine the producible fluid ly used at present. Under this meth­ packer. These three component content of a formation, and (2) to od, a test will usually be made after mechanisms will be found in some determine the ability of a formation penetrating a few feet into the pros­ form in any good drill-stem test tool. to produce. pective zone, and if the results are The functions of each of the basic components in the assembly are as Drill-Stem Testing Methods favorable, subsequent tests may be made in search for fluid contacts. shown below. The drill-stem test, or temporary completion, . can be made either in Testing programs during the early FUNCTIONS OF BASIC COMPONENTS OF TOOL open hole or inside casing through phases of field development are as 1. The Tester or Retaining Valve o. To prevent drilling mud from entering empty perforations. A drill-stem testing pro­ important as the coring and logging drill pipe while funning in. programs for delineation of the res­ b. To aid in preventing drilling mud from enter­ gram can be planned for a well so ing drill pipe while pulling out and, conversely, that the tests will be made in accord­ ervoirs and for establishing or con­ to aid in retaining formation liquid recovery with~ firming the gas-oil and oil-water con­ in the drill pipe. ance with one of three general meth­ c. To open the tool, permitting passage of forma· tacts. tion fluids into the empty drill pipe after the ods: packer is set. 1. Test possibly productive inter­ 2. The By·Pass or Equalizing Valve Trends in Drill-Stem Testing o. To permit mud under hydrostatic pressure to vals in open hole as the zones are Since the early days about three­ flow downward throug h the packer mandrel at the conclusion of the test into the hole below the penetrated; normally, this method is fourths of all drill-stem tests have packer. This action equalizes the pressure above used in conjunction with coring and and below the packer, making it easier to pull been performed in open hole prior loose. to setting oil string casing. This pre­ b. To provide additional area through which the Original manuscript received in Petroleum drilling mud can pass around the packer while Branch office on Sept. 15. 1955. Revised man­ dominance of open-hole testing defi­ running in and pulling out of the hole. uscript received May 1'6. 1956. Paper pre­ nitely places drill-stem testing in Note: The new "hydraulic testers" ore unitized sented at Formation Evaluation Symposium. teater valves and by·pass valves; the respective Oct. 27-28. 1955. Houston. Teo<. the category of exploratory forma- functions of these are unchanged. SPE 589-G JUNE,1956 21 3. The Packer amount of hole to test; (3) packer a core hole, or hole of reduced diam­ o. To bridge the hole at Q point immediately above (and also below on straddle tests) the zon,e to size or sizes; (4) location of packer eter, is drilled ahead for exploratory be tested, thus permitting this zone to be relleve~ purposes. Successful use of conven­ of hydrostatic mud pressure when the tool IS seat; (5) top and bottom choke opened and isolating the zone from other forma­ sizes; (6) probable length of flowing tional double-end wall packers re­ tions. Important auxiliary components of and shut-in period and use of dual quires a very close fit to the hole the drill-stem test tool are as follows: shut-in periods; (7) type of pressure size. Because· of this, a reduction in the disk valve, the shut-in pressure gauges, manner of placement in the hole size or rathole for the last 300 valve or tool, the formation or bot­ tool, and optimum pressure capacity to 500 ft of hole, including the test tom choke, the anchor pipe, and the and clock speed; (8) use of, type, zone, permits greater packer clear­ pressure recorders. In addition to and location of circulating sub, safety ance while running in and out in these, a circulating valve, a safety joint, and jar; (9) use of water cush­ the full hole. Ratholing is largely joint, and sometimes a set of jars ion and amount; (10) method of confined to soft formation areas. may be included in the test tool or handling test production at the sur­ It has been found that the ratio in the drill pipe or tubing string. face; and (11) special packer ar­ of hole size to packer size largely rangements. governs the amount of packer com­ FUNCTIONS OF AUXILIARY COMPONENTS IN pression that will occur at pressure TYPICAL TEST TOOL STRING Amount of Hole to Test 1. The Disk Valve differentials up to 5,000 psi and that o. To aid in preventing drilling mud from enter­ In most instances, a more conclu­ ing the drill pipe while running in. leakage or rupture of the rubber b. To permit the packer to be set firmly and tester sive test can be obtained by testing element will occur if the ratio of valve opened before the tool is finally opened by the shortest section practical. In thin dropping a go-devil to rupture the disk valve (as hole size to packer size is such that used with certain tool assemblies). sands, where it is desired to locate

complete mandrel travel is attained. Downloaded from http://onepetro.org/JPT/article-pdf/8/06/21/2237729/spe-589-g.pdf by guest on 02 October 2021 2. The Shut-In Pressure Valve or Tool o. To permit the test tool to be closed at the con­ the gas-oil and oil-water contacts, a A differential pressure of 5,000 psi clusion of the flow period with reduced likelihood test zone of 2 to 5 or 10 ft is often of unseating the packer or letting pressure equal­ will produce complete compression ize around the packer through the by-pass. used in open hole. Where producing when ratio of hole size to packer b. To aid in preventing drilling mud from enter­ ing the drill pipe while pulling out and, converse­ zones of greater thickness are en­ size approaches 1.25; 5,000 psi dif­ ly, to aid in retaining the formation liquids recov· countered, it may then be feasible to ered within the pipe. ferential pressure will cause about 3. The Formaton or Bottom Choke test more hole per test. This is par­ 50 per cent compression when ratio a. To restrict the volume of formation fluids that flow through the drill pipe to the surface. ticularly true in long limestone sec­ of hole size to packer size is about b. To hold some backpressure under the packer, tions where the location of the porous which reduces the hydrostatic load on the packer, 1.08 or 1.10. In the commonly and to reduce the amount of pressure drawdown in zones may not be known, and it is drilled hole sizes, the 1.08 ratio pro­ the formation. c. To allow quantitative drill-stem test interpreta­ usually desired to determine the over­ vides a reasonable balance between tion. all fluid content and productivity of 4. The Anchor Pipe clearance in true-to-gauge sections a. To support the open-hole wall packer at the a certain interval. If the volume of of hole and the excess expansion desired place in the bore hole. b. To aid in screening out cuttings or junk that the hole below the packer is too available should the packer seat yield might plug the choke or foul other tool com­ great, the drilling fluid may fill the ponents. or be washed out. 5. The Pressure Recorders pipe to such an extent that a low Somewhat larger clearances can be a. To provide measurements of hydrostatic mud formation pressure will be insuffi­ pressure, formation flowing pressures upstrea!," used with the new "expanding shoe" from the formation choke, and formation shut-In cient to cause entry of any appre­ or bottom-hole pressure. These pressure measure­ packers, and in areas where a re­ ments are necessary for complete test interpreta­ ciable quantity of formation fluids duced size hole or rathole need not tion and formation evaluation; therefore, the pres­ against the backpressure. Also, the sure recorders are, in a sense, among the most be used, this type of wall packer has important components of the tool. source of water produced from a b. To provide a graphic record of the proper or excellent application. These packers improper functioning of the test tool. long interval is indefinite. were developed in part to facilitate 6. The Circulating Valve full hole testing by permitting a a. To permit test recoveries to be pumped out of Selection of Packer Size the drill pipe by reverse circulation into a pit or smaller packer diameter to be used tank. b. To provide a means of conditioning the mud W'all Packers than is feasible with conventional in the annul us and thus make testing a safer op­ eration. The open-hole wall packer does packers. 7. The Safety Joint a. To provide a means of releasing the drill pipe not enjoy the controlled conditions Selection of Wall Packer Seats and tool from a stuck packer or anchor. 8. The Jar of usage of the hookwall packer; it Open-hole packer seats should be a. To increase the possibil ity of freeing (] stuck is frequently required to seal off in tool. (The jar used for this purpose is usually a chosen in true-gauged sections of special hydraulic tool designed to deliver impact plastic formations and in a hole hard nonplastic formations. Exami­ blows.) whose diameter is known only ap­ b. To facilitate setting the tool for measuring for. nation of cores will provide the best motion shut-in pressure when a rotating shut-in proximately. Successful use of rub­ pressure valve is not used. (The jar used for this basis for selection of packer seats; purpose is a simple telescoping slip joint arrange­ ber in wall packers requires that the in the absence of visual core exam­ ment.) stresses be kept low enough that the 9. The Surface Control Head ination, a caliper log will be helpful. a. To permit control of fluid flow from the drill rubber will act entirely in the elastic pipe at the surface through means of valves and Electric logs and sidewall cores may chokes. or solid phase; that is, it must return also be of use. When setting packers to its original shape when the load is in the top of sand bodies overlain Planning the Test taken off. This must be done by by soft shale, at least 2 ft of sand keeping the clearance between the should be allowed for the packer The Basic Decisions packer and the wall of the hole as seat. If possible, wall packers should Detailed consideration must be small as practical, by keeping the not be reset in the same seat on suc­ given to a number of factors in plan­ axis of the packer parallel to and ceeding tests. In fractured forma­ ning a drill-stem test in order to in­ coincident with the axis of the hole, tions, use of dual packers (two wall sure that the desired information will and by choosing the packer seat in packers run next to each other) is be obtained and to increase the prob­ the least plastic formation possible. often advisable. ability of a mechanically successful It is important to have a straight test. Decisions must be made before­ true-to-gauge hole and a sufficiently Selection of Choke Size hand on the following: ( 1) service heavy, rigid anchor pipe. The choice of the bore diameter company to be employed; (2) Rathole testing is employed wh.::re of the bottom choke depends upon a

22 JOURNAL OF PETROLEUM TECHNOLO(;Y number of variables, the primary able choke is not available, is to 30 minutes to one hour, has small considerations being safety, test in­ place the position choke up in the effect on the amount of pressure terpretation, and the possibility of drill pipe string above a suitable drawdown in the sand around the the choke becoming plugged. Gen­ amount of water cushion. This slight­ well; and it is truly important only erally, the size of the bottom choke ly reduces the pressure differential in controlling the amount of recov­ should govern the size of the choke across the face of the well bore when ery at the particular flow rate. The used in the control head at the sur­ the tool is opened and assures that rate of production, as governed by face; the bottom choke should con­ a volume of formation fluid at least the choice of choke size, has a large trol the amount of flow and should equal to the volume of the water effect on the amount of drawdown. be small enough in relation to the cushion will be recovered before the Pressure drawdown should be kept top choke size that, barring difficul­ choke plugs. moderate in order to reduce the ties, excessive pressures will not de­ packer load, permit pressure buildup velop in the drill pipe or tubing at Length of Test in shorter shut-in periods, and re­ the surface. duce coning and fingering of gas or If the bottom choke is to be used Flow Period water. as a meter in interpreting for gas-oil Generally, it is better practice to ratio and productivity, the top choke test moderately to highly productive Shut-In Period should not restrict the flow to the zones for a long period with a small At the conclusion of the flowing extent that the backpressure plus the bottom choke (3/16 to % in.) and head due to the recovered liquid on period, it is customary to close the relatively small pressure drawdown test tool on bottom using a rotating the bottom choke is greater than than to test for a short period with Downloaded from http://onepetro.org/JPT/article-pdf/8/06/21/2237729/spe-589-g.pdf by guest on 02 October 2021 about 40 to 50 per cent of the up­ shut-in tool. It is highly desirable to a large choke (¥s to 1/2 in) and obtain a complete buildup of pres­ stream pressure on the bottom choke. more severe drawdown. Under these conditions, the flow is sure in the test zone to the native Two factors are of significance in said to be "critical" and is independ­ formation pressure for the following deciding the duration of the flow pe­ ent of the downstream pressure. reasons: riod: ( 1 ) the length of time for When pressure downstream of the 1. The shape of the pressure build­ which it is safe to leave the drill bottom choke exceeds about 50 per up curve reveals information regard­ pipe undisturbed without danger of cent of the upstream pressure, the ing formation permeability. sticking, and (2) whether the bottom flow rate will progressively diminish 2. The formation pressure is re­ choke is to be used as a meter in as the drill pipe fills. Under these quired for estimates of productivity interpreting GOR and productivity, conditions, the flow is termed "non­ and to ascertain whether an adequate or whether the test is to be flowed critical," and an accurate average (or perhaps excessive) mud weight to surface tankage and interpreta­ rate cannot be determined. is being maintained. tions made by means of surface Bottom choke bores ranging from The length of the shut-in period metering equipment. 3/16 to % in. used with top chokes required to obtain a complete build­ ranging from SIs to I in. are satisfac­ The common use in many areas up is primarily dependent upon the tory for the nonflowing type of test of 20Vz - or 25Vz -minute flow periods formation permeability and second­ in moderately to highly productive for 41h - and 5-in. drill pipe, respec­ arily upon the degree of drawdown zones and where the top choke ex­ tively, is purely an aid toward sim­ caused by the flow period. The feasi­ hausts only air or gas. Bottom chokes plified quantitative test interpreta­ bility of waiting for a complete build­ smaller than 3/16 in. are usually tion. For these sizes of drill pipe, up depends largely upon hole condi­ undesirable due to the ease with the number of feet of liquid recov­ tions. which they will plug. For the flow­ ered during flow periods of these If experience has proved that the ing type of test through tubing where lengths happens also to be the num­ tool cannot be left shut in long the bottom choke is not used as a ber of barrels per day that the test enough, plans may be made to ob­ flowmeter, a 3/16- or %-in. bore would produce during 24 hours serve a partial buildup both before bottom choke used with a top choke through the particular size of choke and after the flow period. This is of about the same bore may prove under critical flow conditions. This referred to as a "dual shut-in" test more feasible. Gas zone tests are amount of time, which might be and is described below. sometimes made with bottom chokes termed as the standard flow period, PROCEDURE FOR DUAL SHUT·IN TEST ranging from % - to ¥s -in. bore in can be computed for any size of 1. The volume of the hole below the packer is calculated and the displacement of the anchor is order to obtain a measurable pres­ pipe by Eq. 1. Standard flow periods subtracted. This gives the volume of the mud only. are suited to moderately to highly 2. The test fool assembly, using a hydraulic sure drawdown. Zones of very low tester valve, is made up with sufficient drill pipe permeability which have very low productive areas where it is not de­ or tubing placed above the hydraulic tester to accommodate 10 to 15 per cent of the mud volume flowing pressures are frequently test­ sired to flow the well, large drill below the packer. A disk valve is placed in the pipe is in use, and the several thou­ string at this point. ed without chokes; however, this 3. The tool is set and the hydraulic tester opened practice is not recommended unless sand feet of oil or water that can in the usual manner, but the disk valve go-devil be recovered in the standard time is not dropped until the initial shut-in time has there is sufficient prior experience to elapsed and a flow period is desired. At the con­ generally will not exert a backpres­ clusion of the flow period, the rotating shut-in indicate that nonrestricted flow is tool is closed and the normal shut-in buildup is safe. sure on the bottom choke in excess taken. of 50 per cent of the upstream pres­ When on bottom and the hydraulic tester opens, In some areas drill-stem testing is the mud pressure below the packer is relieved into sure. For such testing, a I-in. bore the empty drill pipe below the disk valve and the made very difficult due to the choke top choke is often used so as to hold formation is free to produce; however, the pres­ or choke screen becoming plugged ence of the disk valve restricts the amount that the backpressure to a minimum. formation can produce and more complete shut-in with sand grains or pieces of shale, buildup may be obtained in an equivalent time no matter how thoroughly the hole Computed pressure profiles indi­ than can be obtained after the flow period. is conditioned before the test. One cate that when testing sands of mod­ Selection of Pressure Recorders technique of testing under such con­ erate to high permeability, the length No drill-stem test should be run ditions, where a subsurface adjust- of the flow periods ordinarily used, without two subsurface pressure

JUNE, 1956 23 gauges; if possible, one gauge should mation and stick the anchor; (2) it pacKel carries the larger load. If the measure the pressures upstream or may cause plugging of anchor per­ lower packer fails, the upper packer below the bottom choke inside the forations or the bottom choke, and assumes the load. perforated anchor, and the other (3) it contributes to packer failures. should be blanked-off so as to meas­ Flui~ cushions or water blankets Straddle Packer Testing ure pressures outside the perforated can be placed in the drill pipe above anchor. Under this arrangement, the the test tool to reduce the pressure Open-hole straddle testing involves two pressure records should agree differential that occurs across the testing a productive interval which exactly unless the holes in the per­ wall of the bore hole and packer as may be as much as several thousand forated anchor become plugged, in the tool is opened; however, this feet from bottom. A wall packer is which case the ~lanked-off gauge procedure may make test interpreta­ set in a competent seat above and will trend toward the formation shut­ tion difficult, particularly when the below the interval to be tested so in pressure while the inner gauge will recovery is small, because the forma­ that a selected zone may be isolated reflect the pressure inside the anchor, tion liquids may mix with the water for testing through means of a per­ either atmospheric pressure or that cushion. forated nipple which is placed be­ tween the two packers; convention­ due to the head of fluid recovered It is sometimes advisable to use ally, the blank anchor extends to before the plugging occurred. If the fluid cushions when testing high­ choke becomes plugged but the an­ pressure gas sands for reasons of total depth. Use of a straddle packer chor pipe does not plug, both gauges safety. The cushion will effect lower by-pass tool will permit mud pres­ should trend toward formation shut­ surface pressures until it has been sure to be equalized above the top in pressure. The backwashing that produced out of the pipe. Occasion­ packer and below the bottom packer Downloaded from http://onepetro.org/JPT/article-pdf/8/06/21/2237729/spe-589-g.pdf by guest on 02 October 2021 at all times. This arrangement per­ occurs when the by-pass is opened ally, water blankets are a necessity mits leakage of either packer to be will usually clear the plugging mat­ on deep tests in order to prevent the detected by watching the mud level ter from the perforations and may drill pipe or tubing from collapsing in the annulus. It also provides for clear the choke if run under the due to high external mud pressures. equalizing valve; proof that plugging easier release of the bottom packer. occurred cannot always be obtained Gas Cushions Both packers must withstand approx­ solely by examining the tool. Natural gas or bottled nitrogen imately the same pressure differen­ The pressure recorders are built in have been used instead of water to ·tial. The blank anchor below the a number of pressure capacities as provide an initial reduction in the lower packer is not severely loaded well as clock speeds. The service pressure differential applied to the as in a conventional test unless the company should be informed of the formation when the tool opens. This straddle packer by-pass tube is not maximum expected pressure and the is accomplished by pressuring the used and the formation breaks down expected period of time that the tool tubing to the desired amount through or filtration processes reduce the vol­ ume of mud trapped in the hole un­ will be on bottom. The pressure re­ the control head just prior to open­ corder may then be selected, if avail­ ing the tool. This backpressure is der the lower packer. A new develop­ ment is a sub having dogs that can able, so that the maximum recorded then bled off slowly after opening be caused to wedge into the wall of pressure will be approximately two­ the tool. Gas cushions have been thirds to three-fourths of the max­ used to good advantage for drill­ the bore hole to support the straddle tool. imum pressure capacity of the gauge, stem testing during workovers where and the chart travel during the time high-pressure gas is available from Three pressure recorders should on bottom will not cause excessive a gas-lift system. be used-two for the test zone in the usual fashion and one below the overlapping of the stylus traces. If Method of Handling Test the test recovery is to be reversed out Production at the Surface lower packer arranged so as to meas­ with pumps, the pressure capacity The fluids recovered should be ure pressure in the zone under the of the gauge should be sufficient to disposed of in the manner which lower packer. record the mud pressure plus circula­ involves least hazard to the drilling Straddle testing is being applied tion pressure. rig, surroundings, and to the further extensively in the multi-sand forma­ progress of the well. Consideration tions of Southwest Texas, where Location of Auxiliary Tool usual interval tested is about 30 ft Components should also be given to the degree or less and the average distance off The circulation tool is frequently of accuracy required in measuring the volume of recovery. If at all pos­ bottom is about 200 ft and ranges run one to three stands of pipe above up to over 1,000 ft. It is being used the tester valve. This permits reten­ sible, the recovered liquids should be reversed out into a tank or pit. in drilled rather than cored rathole tion of an uncontaminated sample intervals in wells where logs are run of formation liquids, if the recovery Special Packer Arraugements every 500 to 1,000 ft; possibly pro­ is reversed out. The jar is placed ductive zones for testing are chosen above and as close to the packer as Dual Wall Packer Testing by log and sidewall core interpreta­ possible. Two wall packers of the same or tion. There has also been extensive Water Cushions slightly different size can be run one application in the East Texas area With the opening of the test tool, above the other to give added assur­ to permit complete 50- to 90-ft dia­ the pressure on the formation is re­ ance of obtaining a satisfactory seat. mond cores to be cut prior to pulling duced almost instantaneously from The practice is widely used where out to test. mud pressure of several thousand psi there is doubt as to the condition of Straddle hookwall packer testing to the initial flowing pressure or the packer seat, particularly in frac­ inside casing may be employed where sometimes to atmospheric pressure. tured formations. To be effective, there are several perforated intervals This flash release of pressure is un­ both packers should be set in sand and it is desired to test each selec­ desirable for the following reasons: or hard formations. When set in a tively without setting bridge plugs (1) it may cause caving of the for- hard, competent formation, the lower or squeeze cementing.

24 JOURNAL OF PETROLEUM TECHNOI.OG\ Performing the Test Opening the Tool has been high, it may be desirable to Short duration, nonflowing, open­ bleed pressure on a small choke Preparing the Hole hole tests should not be permitted to while rotating; after rotation has The hole may have to be reamed exhaust gas or air to atmosphere clo&.ed the tool, the flow line may be down to reduce the amount of rat­ within the derroick unless it is certain reconnected and the pressure blown hole. Generally, 300 to 500 ft of rat­ that surface pFessUlles will be negli­ down to the pit or tank,s. During the hole is the maximum that is cus­ gible; this applies particularly to shut-in period, the formation pres­ tomarily carried. After reaming, the power rigs. Flow lines should be sure builds up to its static or maxi­ hole should be washed clean to bot­ rigged to the reserve pit and suffi­ mum value under the packer. Unless tom of the remaining rathole and cient flexible pipe should be con­ the formation is very permeable, this should then be circulated at least nected to the control head to permit may require an excessive amount of one cycle. In circulating the hole the pipe to be picked up with a time. clean, the bit should be positioned at minimum of delay to close the tester Pulling Out a point above the packer seat; pipe valve in the event of an emergency. should be lowered occasionally to Care should be taken to see that a At the conclusion of the shut-in period, the drill pipe is raised a foot clear and condition the rathole in the tool joint will not foul the blowout or so while observing the mud level test interval. The trip out to test preventers. Since it may be desired in the annulus. The level may drop should not be begun until such time to pump through the drill pipe or sIlghtly when the equalizing valve as the tool can be made up, run to tubing in case an open-hole test gets opens and mud flows into the zone bottom, and opened with a minimum out of control and since the control of delay or waiting time. Periodic head may be as much as 30 ft up under the packer. After pressure has Downloaded from http://onepetro.org/JPT/article-pdf/8/06/21/2237729/spe-589-g.pdf by guest on 02 October 2021 equalized across the packer, strain tests of mud weight should be made in the derrick, a surface control head may be taken to unseat the packer while circulating so that a reliable to which the kelly can be connected and start slowly out of the rathole. value of the hydrostatic pressure can throughout the test will permit hoist­ Once the packer is clear of the be calculated to check the accuracy ing or pumping to begin with a mini­ rathole, the tool may be pulled out of the pressure recorders. mum of difficulty and loss of time. more rapidly. Care should be taken The same precautions apply to tests Making Up the Tool to see that the well is not swabbed in made inside casing, although the con­ After assembly of the open-hole while pulling out; a torn wall packer trol head is usually accessible for tool, measurements should be taken may bridge even the larger diameter making connections. to check the packer spacing and to main hole. The annulus should be permit the last joint of pipe added to All safety rules regarding smoking filled after pulling each thribble of be marked at the point where it or open fires should be rigidly en­ pipe until it is clear that no swab­ should be flush with the rotary when forced dwring the drill-stem test. Ex­ bing is occurring and then at least the tool is just touching bottom. This plosion-proof safety lights should be after each three thribbles or more procedure permits the tool to be dimmed or turned off, while unpro­ often, depending on drill pipe size, eased into contact with the bottom tected light bulbs should always be last casing size, mud weight, and of the hole and provides a check on turned off. Power rig engines might the mud overload pressure being the weight indicator; weight indicator best be idled in order that hoisting carried. Should the annulus be filled readings alone may lead to difficul­ power will be available without de­ and overflowing continuously, it may ties if true bottom has not been lay, provided the test flow is directed not be possible to determine whether reached. A similar procedure should to a pit or tank off the rig floor. .Tust the overflow is from the pumps or be used for testing inside casing, and before opening the tool, the annulus due to swabbing action. The per­ the mark should be placed so that should be filled if necessary. Close missibility of rotating out of the the lowest part of the test tool will watch on the annulus mud level hole depends upon what components be the necessary distance above the should be maintained when the tool are included in the tool string. top perforation so as to permit the is opened; a sudden drop in fluid surface control head to be conven­ level indicates that the packer is not Reversing Out Test Recovery iently accessible from the derrick sealing. A very slow loss of fluid is When the recovery is oil, removal floor. not serious since it is usually caused by pulling wet stands involves a defi­ by a loss of mud or filtrate to a frac­ nite fire hazard since the oil is Running In tured or porous zone; however, con­ dumped from each stand onto the The speed at which the tool can be stant vigil should be maintained floor and cellar as the stands are run to bottom should be at least 25 throughout the test and the mud level broken out. In addition, gas pockets per cent slower than usual; a mod­ kept in sight at all times. within the column of oil may cause erate amount of spudding is possi­ Before opening the tool, the high­ heading of the oil from the top of a ble. From time to time while run­ pressure rubber hose provided by the st-and high up in the derrick. The re­ ning in, the drill pipe should be service company should be connected sulting cold spray can be ignited by checked for leaks by observing from the control head to the gauge causing hot light bulbs to explode, or whether or not air is flowing from manifold on the rig floor; the end of by blowing onto magnetos and hot the pipe and by observing the the hose may be held in a bucket of exhaust manifolds on power rig en­ amount of spill-over that occurs as water to allow the increased hlow gines, or the boilers on steam rigs. each stand is lowered into the hole. that will occur when the tool is The inclusion in the string of a reverse circulating sub which can be If it becomes necessary to shut down opened to be detected immediately. opened to the annulus at the conclu­ with the tool only part way to bot­ Shut-In Period sion of the test will permit the oil to tom, close watch should be kept on At the conclusion of the flow pe­ be flowed or pumped by reverse cir­ the annulus mud level to determine riod, the tool is closed by means of culation to a pit or tank with relative that mud is not entering the pipe the rotating shut-in pressure valve. safety, even at night. This is particu­ through a leaking tool or tool joint. On gas tests, if the flowing pressure larly desirable in the case of hook-

JUNE, 195() wall packer testing inside casing Salt Water Samples yields only formation water, the mud since this type of test is usually con­ Absence of oil or gas in a tested below the packer is displaced up­ ducted for a long enough period to formation cannot be considered ward into the drill pipe by water en­ permit the pipe to be entirely filled proved unless evidence is obtained tering the well bore. At first this with formation liquids, and pump that representative formation water water is mud filtrate, followed in pressure can be applied to the annu­ is recovered. During the course of a turn by salt water. Fig. 2 illustrates lus while the packer is set with min­ study of subsurface waters in which the resultant variation of salinity imum danger of breaking down the a large number of drill-stem tests with depth in the recovered water formation. Reverse circulation in were made for the specific purpose column. The salinity increases rapid­ open hole is less attractive because of of obtaining representative water ly below the mud to a maximum this danger, hazard of sticking the samples, a system of sampling was constant value. Any part of the water pipe, and difficulty in accurate meas­ column having this maximum con­ developed by M. S. Taggart, Jr., of urement of small-volume recoveries. stant salinity is representative forma­ Production Research Division, Hum­ When fluid recovery is believed to tion water, or very nearly so. ble Oil & Refining Co., which per­ be large, a suggested procedure for From the point of view of sam­ open-hole reversing is indicated mits determining by examination of pling, it may be seen that a sample below. the samples themselves whether rep­ taken just below the mud would have resentative water is produced. The had a chloride content of only PROCEDURE FOR OPEN HOLE REVERSING following examples have been se­ 32,000 ppm, whereas the true chlor­ 1. At conclusion of flowing period, place 500 to 1,000 ft of fresh water of known chloride in lected from the results of this study ide content of the formation water the drill pipe. was about 66,000 ppm. Except in ex­ Downloaded from http://onepetro.org/JPT/article-pdf/8/06/21/2237729/spe-589-g.pdf by guest on 02 October 2021 2. Pull pipe until water is encountered. Check to illustrate the variations of salinity that pump is primed and ready. of the produced water frequently ceptional cases, such as after acidiz­ 3. Open circulation sub and reverse out fresh encountered under different condi­ ing or when the drilling mud is of water and formation liquids by letting mud "U· very high salinity, the water samples tube" into pipe; keep the annulus filled. Control tions of drill-stem testing. flow from pipe with a suitable choke. If blowout with the highest salinity are those preventer must be closed, use as little pump pres­ sure as is necessary, and count pump strokes while Typical Su.ccessfu.l Test which more nearly approach true formation Iiquid~ are flowing to assist in deter­ mining volume; if may be desired to rotate pipe In the usual drill-stem test that formation water. while reversing, if a swivel-type surface control head is available. 4. Pull remaining pipe and remove circulation sub; place a solid-type thread protector or plug in each of the remaining two to five thribbles, as each is pulled, and use a sealed mud saver when breaking out. The purpose of the plugs is to pre­ vent heading of oil from a thribble that has been raised into the derrick. Taking the Data Some type of drill-stem test opera­ tions report should be filled in. A sample form is 5hown on Fig. 1. It should be remembered that the re­ sults of the drill-stem test data may be reviewed years after the test by reservoir or workover analysts, who

will depend heavily on thorough, <: ....' ..0 .nv'.. o., o. D 9% _IN __ .!'OL~ ...DATA_ ' ... 10 ..... NOI..Il, .,n D"LD HOLC ~," .1lT ... , II.,. ~. - ~. - n .Lin ,,"'THOLC ~'''. adequate reports for guidance. TOT.. L oc...... A#o n_. ,o~ 0" ""'''OLC''V .990 n., .... O""'T D' ""V.. O\.C $D n

Drill-Stem Test Interpretation OPERATIONS TIME RECORD Fluid Content -,4~·~So~_,,,.,,.,_.,:t L ....'V .. "' ••LC'''' ..O\..· "S'8 'o"~rro"~"_ 7 :''6z 'O"p""'_" When formation liquids are re­ ~~ ~---- versed out or when the pipe is .,,,",,,""'.. "00. ~ _-__ '''. OUTD' ..OLI: ~ _-__ pulled from the hole, an account of ....."'oo.=o~"~"" .. ~.'" the liquids recovered should be taken, ... ~"'~ro~ •• o.'"~".~ .... both as to type and the volume in barrels. The gravity of the oil should be taken. It is important that the re­ covery of all liquid be measured MEASURED AND COMPUTED PRESSURE DATA accurately as it is from this measure­ ment that the rate of production in barrels per day may be computed. ESTIMATED PRODUCTIVITY DURING TEST

o P~OOUCTIVITY INDEX The volume of rathole mud recov­ uN~ ~~+~. ~ -m~---:i!fjli!"~~{ ered should be approximately equal p"cltqr+ _ to or less than the volume of mud ;;~~:;':N 7. ;;;;".:::::,:;:": ~.:::~~: :;::;.:~::~:~.;;;,r:;q.~ that was originally trapped below the "'..... " ••~. DllTl".. '''' ... VIO" 0 .. "L"'D <:OH,.",.&"'SfIlCMl::f ~. on'[I,,,,,,,,,,,,o .. _ ~00U<:V1VIVV '/ii+JlijiiCb";t Bottom -' fcct of 10re ,.",,/ mile' u.ty .. hpJ« packer in the test zone. A larger vol­ ume of mud in the recovery may be .....n.,-eIlONII~m ... VOII,~ indicative of a fractured or vugular ~.~"'''CO OH.~. I IHftIl",OCO.V: = formation, provided that the mud level did not fall in the annulus dur­ ing the test. Fig. I - Sample record of a drill-stem test.

26 JOIJRNAL OF PETROLEUM TECID,OLO(;Y Effect 0/ Leaking Packer pIes, on the other hand, permits the the individual test. The upper portion Fig. 3 illustrates the effect of a determination from the variation in of Fig. 6 shows the typical configu­ leaking packer on the variation of salinity with depth in the recovered ration, the conventional sequence of salinity with depth in the recovered water column of whether the pro­ events, and the relative magnitude water column. A sample taken im­ duced water is representative. of the corresponding pressures. Sim­ mediately above the tool in this test The per cent of salt water recov­ ilarly, charts from tests performed in would have had a salinity about 24 ered may be estimated by dividing the conventional sequence but which per cent less than that of the forma­ the number of barrels or feet of for­ were unsuccessful for one of the tion water. Likewise, a sample taken mation salt water by the number of more common reasons will have a near the top of the column would barrels or feet of total liquid, exclu­ characteristic configuration which have had a salinity much too low. sive of rathole mud; however, such discloses the reason for the failure. percentages may be erroneous when The lower portion of Fig. 6 shows Effect of Inadequate Yield the test is of short duration and the these typical configurations. Drill-stem tests sometimes recover amount of recovery is small. Basic but minor differences in gen­ only mud and mud filtrate, the yield eral chart configuration for conven­ Pressure Measurements -­ being insufficient to result in recovery Chart Interpretation tional sequence tests of moderately of formation water. The mud flltrate Test interpretation, aside from the to highly productive zones will oc­ may have become contaminated with visual examination of the liquid drill­ cur during the flow period, depend­ salt from the formation or by mix­ stem test recovery, requires prelimi­ ing on which of the following two ing with formation water and m

JUNE, 1956 ter the test zone to cause a slow where little oil, condensate, or water value of Q, the gas production rate, buildup of pressure. Such formations is produced can be estimated from in Mcf per day on the horizontal should not be rejected too hastily in the charts. scale, view of the potentialities of acid Ability of the Well to Produce 4. Draw a line through this point treatment or fo~ation fracturing up and to the right at a 45° angle to processes. Open Flow Potential the vertical axis. Fig. 7 shows schematic examples 5. Draw a line parallel to the hori­ of the several conditions discussed Frequently it will be desirable to zontal axis along the value of Ps," in above. estimate the open flow potential of a thousands. At the intersection of this gas sand interval from drill-stem test Gas-Oil Ratio line with the 45° line, read the value data. A reasonable estimate of open of Q, in Mcf per day, which is the If little or no water is produced flow potential based on data for one approximate open flow potential of during the test, the gas-oil ratio may rate of flow can be obtained as fol­ be estimated by using the charts, lows: the tested interval. Figs. 8 and 8-A. The rate of gas 1. Estimate of Mcf per day gas production during tests of gas zones Productivity Factors and Specific production rate, Q, during the drill­ Productivity Factors stem test by the procedure described 12r----,------r------,------, e... n,on in the preceding paragraph. An index of the ability of the \ 2 2. Evaluate: (P - P/) formation to produce liquid can be ' ..... ---i-___: . + si Where, Psi = Formation shut-in obtained from the nonflowing type 10 -- -",-..c-=-t-- --+--+--- Downloaded from http://onepetro.org/JPT/article-pdf/8/06/21/2237729/spe-589-g.pdf by guest on 02 October 2021 , , pressure + 15 psia of test usually employed for explora­ + = P r = Average flowing pres­ tory testing in open hole. This re­ sure + 15 = psia quires very accurate measurement of 3. On log-log graph paper plot the the length of the flow period, amount 2 value of (P'i - P/) in thousands of recovery, and the formation flow­ on the vertical scale against the ing and shut-in pressures. A produc-

-- CRITICAL FLOW - -- NON· CRITICAL FLOW

CHLORIDE CONTENT: PPM Fig. 4-Example of unsufficient yield to recover representative water.

45

TIm.

I PRESSURES: A-tNlTlAL MUD EVENTS' 0 -I.t THRl88LE IN b-LAST THRI88LE IN 8 • PACKER SQUEEZE e -ON BOTTOM d-PJI,CI(£R SET j\ C - AVE. FLOWING • - TOOL OPfNEO f -TOOl CLOSEO '" I O-SHUlIN 1-BUlLO UP COMPUTE Well No. 1 ~ E- FINAL MUD tI - EQUALIZING VAL.VE OPENED DST 5134·5195 ft. --... O-c - ORAWOOWN I - MQ(ER UNSEATED J - 1st THRUL.E OUT k - LAST THAl88LE OVT in open ~ol. I - nWE RUNNINe IN 35 2- FLOW PERIOD TYPICAL CHARTS FROM 5 - SHUT IN PfRIOO A SATISFACTORY TE ST 4 - TIME PULLING OUT I

<5 JO (TOP GAGE NOT BLANKED OFF. BOTTOM GAGE BLANKED OFF) g LEGEND: -- TOP CHART (OR 80TH CHARTS) I --- BOTTOM CHART ~ 0 (CRITICAL FLOW) g ! \ '" 2S a:~ -' -' ii' 0 20 ~ "- 0 I Well No. B-1 l'i z DST 513()'5154 ft. - ..... thrjugh perforct,oi' ~ 15

! I PACKER FAIL£D NO SHUT-IN PRESSURE ! ,! 10 . ,/_TJI\ " i'+-! \ i I ~ \ . , , i ' I I \ i . ' \ i I 1rtA C \ 0 E j I \ 20,000 40,000 60,000 so,ooo OILORIDE CONTENT: PPM CHOKE PLUGGING ANCHOR PLUGGED TOP CLOCK STOPPED I} STARTED Fig. 5 - Example of failure to test Fig. 6 - Pressure chart interpretation: Typical charts from a satisfactory test formation behind casing. and charts from common types of mis-run.

28 JOURNAL OF PETROLEUM TECIlNOLOt;) tivity factor or index is computed from these data. The productivity, or PF, is defined as the ratio of a constant formation 2- - 3 liquid production rate, barrels of oil plus water per day, to the pres­ sure drop opposite the sand face. The utility of the PF results from NO PERMEABILITY VERY LOW PERMEABILITY SAND FACE POSSIBLY PLUGGED the fact that the variation in sand face pressure in good to strong wells is usually a linear function of pro­ duction rate. The specific productiv­ ity factor is the PF divided by the net productive feet of exposed pro­ ducing interval as judged from ex­ amination of cores or logs. The spe­ cific PF has an approximate linear relationship to the ratio of effective HI-GH PERMEABILITY ON HIGH PERMEABILITY ON HIGH PERMEABILIty WITH permeability to viscosity, millidarcys 3116- BOTTOM CHOKE 1/4- BOtTOM CHOKE NO BOTTOM CHOKE (CRtlICAL FLOW) (CRITICAL FLOW) (NON-CRITICAL FLOW) per centipoise.

The PF and specific PF can be Downloaded from http://onepetro.org/JPT/article-pdf/8/06/21/2237729/spe-589-g.pdf by guest on 02 October 2021 computed from drill-stem test data as outlined by Eqs. 1 through 4. - 2 , - Use of Produtivity Factors The relationship given in Eq_ 5 DE can be helpful in investigating the possibility of obtaining flowing pro­ GAS TEST - UNLOADED WATER CUSHION EXCESSIVE FLUID HEAD INSIDE PIPE duction by assuming a minimum 0- WATER CUSHION RISING TO SURFACE FLOWING PRESSURE UPSTREAM OF CHOKE b- WATER CUSHION BEING PROOUCED REMAINED CONSTANT UNTIL THE BACK satisfactory tubing pressure and a c- FLOWING DRY GAS PRESSURE DUE TO LIQUID ACCUMULATION maximum gradient; for example, the d- TOOL SHUT IN INSIDE PIPE BECAME EXCESSIVE, RESULTING IN A DIMINISHING FLOW RATE. dead oil gradient corresponding to the API gravity of the oil or a gra­ Nor€: rH€ RUNNING IN AAO PULLING our PERIODS ON rH€SE CHARrS dient corresponding to a mixture of ARE SHOWN COMPRESSED ON riME SCALE FOR CLARlrr. Fig. 7 - Pressure chart interpretation: various testing conditions. oil and an estimated per cent salt

,= ~ ,,~ .. ," .. 'O~ ..

...> '

,~ .. " I" " Ift.o " '" ",+H++-H--f1-H+f-1H--+H++-H--+H+---frH " '" .'~ :~: .~.Jo , r'~ " "oF'~'I;-' +-H+++-A--+++UP~E. FI(lUR{S FOR 1I4'~, CHOkE " :: :+++~t~f=-1-~t+~t+'=-t---t"-'t-'"-1'-""+'-"H'-+O'-'t-"---t"'-,"+O-"H4/+·l--rH4J< " I ,. ..0 V

Fig. 8 - Gas-oil ratio chart: ¥s- and *-in. chokes. Fig. 8A - Gas-oil ratio chart: 3/16- and 3/8·in. chokes. Flow of fluid and gas through 1/8- and 3/16-in. by 6-in. chokes. Flow of fluid and gao through 1/8- and 1/4-in. by 6-in. chokes. (Plotted from test data for downstream pressures less than 125 psi (Plotted from fest data for downstream pressures less than 125 psi for values of /10 from 0.5 to 2.0 and API gravities from 32 to 42) for values of /Lo from 0.5 to 2.0 and API gravities from 32 to 42)

JUNE, 1956 If which agrees closely with the bottom gauge read­ water. substantial production is ing of 5,818 psi. The bottom gauge was then indicated by this method, flowing assumed as reasonably accurate. 2. Check for complete pr~ssure buildup production is probable since the ac­ Since the bottom gauge pressure chart was nof tual flowing gradient will be reduced available for examination and since the summary did not indicate whether or not the shut-in pres­ by dissolved or free gas. sure buildup was complete, a check on the normal --- -+ -_.- shut-in pressure for the depth was made by ex­ Use of Specific Productivity Factors amining initial reservoir pressures measured in other producing reservoirs of comparable depth in At times it may be of interest to the area. It was found that an initial shut-in gra­ dient of 0.465 psi/ft subsea was normal for the make an estimate of the effective area. The elevation of the well in question was permeability of the tested zone. This taken as 0 ft for convenience since it was known that a borge rig was in use. estimate may be made by utilizing Computed normal pressure was: 10,866 X 0.465 = 5,050 psi the approximate relationship, given This was considered a reasonable check with the by Eq. 6, between specific PF, the 5,025 psi recorded by the bottom gauge and the formation pressure was assumed to be 5,050 psi viscosity of saturated reservoir oil since buildup may not have been complete. at reservoir temperature and pres­ 3. Check for critical flow during test In order to determine that the recovery entered sure, and effective permeability. the pipe at a constant rate, the head on the bot­ tom choke due to the recovery was computed and Subsurface sample analysis is re­ found to be less than 50 per cent of the upstream quired to determine the viscosity of recorded maximum flowing pressure of 4,380 psi. the reservoir oil; however, examina­ Head due to 1,100 ft of oil and 180 psi surface VISCOSITY OF SATURATEO RESERVOIR OIL AT Po&. T,. CENTIPOISE pressure: Fig. 9 - Correlations of API gravity tion of a large number of analyses 1,100 X 0.35 + 180 = 565 psi as compared with: 50 per cent of 4,380 = 2,190 with viscosity. revealed that for reservoir tempera­ psi. tures between 140 and 240°F, the 4. Compute daily production rate during test Downloaded from http://onepetro.org/JPT/article-pdf/8/06/21/2237729/spe-589-g.pdf by guest on 02 October 2021 Since critical flow seemed evident, the produc­ R = F when Bf X 1,440 viscosities of saturated reservoir oils tion rate during the test was computed using Eq. 1 correlated reasonably well with API 0$ follows: L F gravity of residual oil after flash R = T X 8f X 1,440 Productivity Factor =

separation at 0 psi. The correlation = 1,100 X 0.01778 X 1;440 Production Rate BID is shown on Fig. 9. 25.5 Pressure Drawdown (psi) = 1,100 B/D 5. Compute estimated productivity factor (2) Sample Drill-Stem Interpretation The productivity factor was estimated by using The problem occurs frequently of 1,100 BID production, 5,050 psi formation pres­ F sure, and 4,380 psi flowing pressure: L Bf 1,440 determining whether or not a drill­ 1,100 4 /D . d d PF = (3) stem test has indicated that com­ (5,050 _ 4,380) = 1.6 B pSI raw own P,j - P f mercial production can be attained. 6. Estimate gas-oil ratio Gas-oil ratio was estimated to be about 1,000 'fi PF There are methods of analyzing the cu II/bbl Irom Ihe flow chari lor 3/16·in. choke, Specl c PF = ------Fig. 8·A, using 1,100 B/D and 4,380 psi flowing Feet of Net Pay test data which at least present a pressure. basis for founding opinions, even 7. Evaluate possibility of flowi.ng production (4) Having evaluated the productivity factor, it was R PF (P" - P t - P f ,. - DX Gr) by personnel not too familiar with possible to check the probability of flowing pro­ the area. It must be realized even the duction as follows: {a} assumed no water produc­ (5) tion would occur, and (b) assumed a maximum broadest conclusions resulting from gradienl 01 0.370 psi/It due 10 dead 35.5° API K = 1,000 (Specific PF) V (6) such analyses are subject to unavoid­ oil. The amount of production theoretically possible Symbols: able error due to the number of even with this extremely high gradient was ,om­ puted as follows, using Eq. 5, and assuming 500 R = Flow rate, BID variables that exist. Ib combined tubing pressure and friction pressure loss: F = Liquid recovered, ft The following is an example of a R = PF (P" - p, - PfT - D X Gr) complete drill-stem test interpretation = (1.6) (5,050 - 500 - 10,866 X 0.370) L = Length of test, minutes = 850 B/D Bf = such as might be made from a typ­ 8. Estimate effective permeability Pipe capacity, blft ical "morning-wire" drill-stem test The specific productivity factor and effective per­ = meability were evaluated using Eqs. 4 and 6. A 1,440 Minutes per day summary in the form previously formation volume factor of 1.25 was assumed. The Gr = Flowing gradient, psi/ft suggested. viscosity of the 35.5° API oil at reservoir condi­ tions was estimated at 0.5 cp from Fig. 9. V Viscosity of saturated oil DST OF FORM FROM 10,889' 10 10,898'. 7" PF WAll PKR SET AT 10,889'. 3/16" BTM CK & '/" Speci fie PF = Feet of net pay at reservoir condition TOP CK. TOOL OPEN 25V, MIN & SI 30 MIN MAX SURF PR 180#. REC 20' MUD & 1,100' OR 1.64 P" Formation shut-in pres- 19.5 BBlS OF 35.5 DEG API GRAY OIL NO S/W. 9 CHl OF MUD 7,200 PPM. PR CHART AT 10,861' sure, psi IMP 5,925# MFP 4,445# AFP 4,445# SIP 5,146# = 0.18 slock·lank B/D/psi/It FMP 5,995#. PR CHART AT 10,866' IMP 5,818# 0.18 X 1.25 = 0.225 reservoir B/D/psi/It Pf Formation flowing pres- K = 1,000 (Specific PF) V MFP 4,380# AFP 4,380# SI P 5,025# FMP 1,000 (0.225) (0.05) sure, psi 5,890#. = = 112 md 1. Check accuracy of pressure gauges P t = Tubing pressure, psi Initial mud pressure from the top gauge WQS 5,925 psi, as compared with 5,818 psi from the P fr = Friction loss, psi bottom gauge, a difference of 107 psi. A check APPENDIX indicated that mud weight was 10.2 Ib/gal at the D = Completion depth, ft time of the test. Computed initial mud pressure due to 10.2 F K Effective permeability, md Ib/gol mud was: R X Bf X 1,440 10.2 X 10,866 X 0.052 = 5,750 psi L PF Productivity Factor It was noted further that initial mud pressure (1) due 10 10.3 Ib/gal mud would be 5,815 psi, ***

30 JOURNAL OF PETROLEUM TECHNOLO(;\