46

What’s New in Well Testing?The key to increasing well productivity and total recovery lies in understanding fluid

which is undergoing innovations that enhance both its safety and performance.

Gavin ClarkHouston, Texas, USA

Henri FreyssModeratorHouston, Texas, USA

Gary CrawfordBP ExplorationHouston, Texas, USA

WELL TESTiNG

Well Test ObjectivesModeratorHENRI FREYSS

Let’s begin with setting the foundation: How do you define welltesting?

MOUNIR EL-HALABII think of well testing as analysis of dynamic characteristics ofthe reservoir through measurement of pressure transients.1 It alsoincludes collection and analysis of fluid samples.[General agreement]

FREYSSOnce you decide to test a well, how do you define the testobjectives?

GARY CRAWFORDIn the past, well test objectives were inferred. Everybody said,“Let’s do a well test.” You had to press for identification ofexactly what they were trying to find out. Within the last fiveyears, three improvements in technology—the high-resolutionpressure gauge, interactive computer graphics and derivativeinterpretation—have completely changed analysis of well tests.Because we can provide more information, we have more optionsin the objectives and so need to identify them more carefully.

FREYSSGive me an example. Do objectives differ for exploration,appraisal and development wells?

Oilfield Review

flow. The critical step in this quest is well testing,

Mounir El-HalabiAnaco, Venezuela

Rob HaighAdams Pearson Associates Inc.Calgary, Alberta, Canada

Jeff MacDonaldConoco, Inc. Houston, Texas, USA

Larry MyersMobil Exploration andProducing Services, Inc.Dallas, Texas, USA

Evan SimmonsChevron OverseasPetroleum, Inc.San Ramon, California, USA

In this article, DataLatch, IRIS (Intelligent Remote Implementation System), (LINC)Latched Inductive Coupling), MDT (Modular Formation Dynamics Tester), MFE (Multi-flow Evaluator tool), MSRT (Multisensor Recorder/Transmitter), PCT (Pressure Con-trolled Tester) and RFT (Repeat Formation Tester) are marks of Schlumberger.1. Pressure transient analysis is the evaluation of pressure variation with time as a func-

tion of changes in flow rate, controlled either from valves at the surface or down-hole. It is used to determine parameters controlling fluid flow.

JEFF MACDONALDTesting of exploration wells always has the same objectives:collection and analysis of a representative fluid sample andsome information on rock properties and the well’s productivecapacity.

In appraisal wells, you already have this initial information soyou can expand your horizons and design the test to answerother specific questions. These questions will be different foreach well, but typically you want an idea of, for example, reser-voir continuity and completion efficiencies.

In a development well, you’re after baselineinformation—such as production logs, flow profiles and initialproductivity information—that will help in future reservoir man-agement. The last ten years have seen a shift in testing philoso-phy in that more companies are spending money on data acqui-sition in development wells in the initial stage of a project. Thisimproves the quality of reservoir management decisions that canbe made during the life of the field.

ROB HAIGHI’ve got an example of this. We worked with an operating com-pany on a wildcat well that had oil shows during drilling, so theoperator went in with openhole testing tools. During a very shorttest, the pipe partially filled with oil. There was some excite-ment. They cased the well, did cased-hole DSTs [drillstem tests]and tested the zone for about two hours. The pipe filled with oiland stopped flowing. After some analysis they concluded this

April 1992

was an underpressured reservoir with a gas/oil ratio [GOR] solow that the well wouldn’t flow to surface. Based on results ofthis test, they provided electric submersible pumps to further testthe well. This allowed further analysis to prove it was capable of50,000 barrels per day from a very short completion interval.The PVT [pressure, volume and temperature] properties are suchthat the well wouldn’t flow to surface.

This shows how test objectives evolved and that each phaseof testing had a slightly different objective. The first test provedoil was there. The second explained why the well wasn’t flowingto surface. This test indicated a good chance of acceptable pro-ductivity, which allowed the operator to roughly size the pumpsystem and run it for about a week—an expense they undertookonly because it was justified by the sequence of favorable testresults.

FREYSSYou’re hinting that economics drives the objectives of a well test.As a consequence, are test objectives more focused today thanin the recent past?

47

4

LARRY MYERSCost does dictate test objectives, but I think objectives are morefocused because there is better awareness amongnontesters—management, drillers, log analysts,geophysicists—of what testing can and can’t do. They’re morelikely to work closely with you to achieve test objectives. In anappraisal well offshore Indonesia, we had good cooperation andconsequently got excellent data on one test that enabled us toreduce the number of wells required to develop the field. In thepast, we would have probably planned a much larger develop-ment because our inflow performance data would have notbeen good enough.

HAIGHCooperation of drillers and reservoir engineers is essential toachieve test objectives. We’ve seen test results collected 15years ago by a drilling department that didn’t recognize therequirements for shut-in. The foreman decided to bull head2 thetubing contents just to make sure the downhole valve was open,destroying any reservoir interpretation. We’ve learned that com-munication is the key both to avoid this and to meet test objec-tives. Now we put the reservoir engineer, geologist and drillingengineer together to discuss test programming, and have a reser-voir engineer on site during testing. Often, the drilling foreman isafraid of bringing live hydrocarbons to surface—he thinks itmeans his well control is messed up. Yet, the reservoir engineerwants live hydrocarbons to test the well. They’ve got oppositeobjectives. You can’t have this and get good tests. Once thesepeople start talking and get comfortable with one another’s pro-cesses, everyone’s needs are met.

EVAN SIMMONSTo facilitate this communication, and start it early enough toaffect test planning, Chevron has a group of five people who testall of the company’s exploration wells worldwide. No test isconducted unless one of these five people is on location. We alsorun schools to educate drilling and exploration groups abouttesting tools, the data we’re after and why we want them, the timeconstraints and how to modify the testing program midstream.

CRAWFORDCertainly communication is essential, but new technology hasalso sharpened our focus on test objectives. In the past, opera-tions personnel involved in testing could not analyze the resultsin a timely manner. The data came in and were sent to theoffice, where someone made a plot. If we made the plot on therig, it was after testing was completed. Now, we can downloadand analyze data so fast that we can explain on location whatwe’re lacking and identify in real time if we need to revise testprocedures or objectives.

8

2. Bull heading is pumping through the tubing into the formation. This can be used tocheck that the downhole valve is open. If the valve is open, pressure bleeds off intothe formation. This procedure may interfere with test interpretation by forcing drillingmud into the formation, thereby damaging it.

Safety and EnvironmentFREYSS

Do we have better control on safety issues today than in the past?MACDONALD

Our first priority is to conduct tests in a safe and environmentallyaware manner. Despite improvements in technology that help usmeet this priority, DSTs remain the most dangerous activity car-ried out on a rig. You’re bringing live hydrocarbons to surface,generally through a temporary production setup. Anytime youdo this you are exposed to an increased potential safety hazard.

CRAWFORDI think the most dangerous time is during drilling. Most accidentstake place during drilling because we spend more time drillingthan testing. But I contend that if we can safely drill a well, wecan safely test it.

EL-HALABIIncluded in this subject is testing of sour reservoirs. In somewells in our new fields in western Venezuela, we are surprisedwith high hydrogen sulfide [H2S] concentrations, up to 400ppm. These high concentrations are usually associated withmedium oil. This obliges us to change our testing program to ashort flow period and shut-in period, after which the tubing isflushed with a calcium carbonate solution.

Oilfield Review

nFlaring during anoffshore well test.Oil produced duringa test is burned toavoid problems ofstorage or pollution.Oil flows from theseparator to theburner, where it iscombined with com-pressed air andatomized in aswirling motion. Theoil-air mixture isignited and water issprayed into theflame about 6 ft [1.8m] from the burnerhead. This waterevaporates in awater-gas reaction,which prevents pro-duction of carbonblack. The flameburns clear and yel-low, without falloutof solid particles ofunburnt oil and it is75 to 100 feet [23 to30 m] long.

FREYSSIncreasingly, well testing in many places is constrained by envi-ronmental regulations. How do you cope with these constraints?

CRAWFORDThere’s a tendency in the industry to avoid doing the workinstead of figuring out how to do it in a safe and environmentallysound way. I think we need to be more enterprising in findingways to get data and still meet operating constraints.

MYERSOne way of meeting environmental concerns is to talk with localregulatory bodies and other companies that have worked in anarea—taking the extra step to find out what is required. Forexample, we found that the topsoil in one area of Papua NewGuinea was porous and so precluded flowing hydrocarbons to apit. Hydrocarbons would have seeped into the soil and fouledthe groundwater. So we burned off hydrocarbons using a burnerthat we would normally use only offshore.

GAVIN CLARKThis raises the burning question—if you’ll excuse the pun—offluid disposal. Regulations are becoming more restrictive onwhat you can bring to surface, dump overboard or burn off(above). How do you cope with this challenge?

April 1992

MACDONALDOur group is beginning to study what it would take to achievewhat we call zero-discharge testing. At this early stage, we takezero discharge to mean no burning of liquids. Instead, we mightreinject all fluids or contain them and find another means of dis-posal. Closed chamber testing, in which no fluids are brought tosurface, is an option, but these tests provide limited information.

MYERSWe’ve had similar concerns in Australia. Closed chamber testsdon’t give us all the information we’d like. Longer productiontests would tell us what we want to know. One considerationwas to put the fluids in a contained vessel for zero discharge, butthis increased our safety risks. We elected to set up multipleburners with backup compressors. Containment booms wereavailable and ready for deployment if required. Of course, 24-hour surveillance was also set up.

MACDONALDWe have that same quandary in operations in tropical rainforests. Traditionally, to burn we would have to clear a largerarea. But today, clear-cutting is alien to how we want to operate.We want to minimize our environmental footprint. This isanother reason for moving toward zero-discharge testing.

49

Current AdvancesFREYSS

What do you consider the most important recent advances inwell testing?

MYERSThe DataLatch system, for retrieving data with the tools stilldownhole, is a move in the right direction (left). The mainadvantage is flexibility in how we get data. For example, we canrun the inductive coupling in the well after shut-in and begingetting buildup data, and we can change sample rate if needed.We see as a possible disadvantage that we still have to predictthe sample rate needed during the flow period. And we still havea wireline to contend with.

CRAWFORDTool reliability comes to mind first. When I started out, we hadto go through all kinds of manipulations to get DST tools tooperate. Now tool reliability has significantly improved. Otherkey advances, I think, are in pressure gauges and our ability toanalyze pressure data. The new electronic gauges outperformmechanical gauges in reliability, range, precision and accuracy.And our utilization of pressure data has improved because ofadvances in computers and data analysis techniques. In the past,when we first started taking derivatives, we debated for hoursover essential questions: How do we take the derivative, how dowe smooth it, and when do we stop smoothing? Now we getderivatives instantly and can manipulate them in real time. If wehad today’s technology back in 1978, when Prudhoe Bay[Alaska, USA] came on line, we could have known vertical per-meability from the well test data. But we didn’t, so we had towork on it for 15 years.

HAIGHAnother factor is that operating companies are becoming smarterabout how to run tools. This includes the order to run them in,how to condition the mud to optimize tool response, and how toget mud that works at high temperature and pressure withouthaving solids settle out and plug up the tools. Everyone has alsonoted better pressure data. I think pressure gauges haveadvanced to the point where pressure data greatly exceed flowrate data in quality. On a test flowing at around 5000 barrels perday, the rates can deviate by ±500 barrels to—in a goodcase—±50 barrels.

MACDONALDAccuracy and resolution of flow rate data are still an order ofmagnitude worse than those of pressure data. Nevertheless, we’velearned a few ways to reduce this uncertainty. If we’re testingthrough a separator and we have adequate stock tankage, wedesign the setup to permit both tank and separator measurements.

SIMMONSWe’ve mentioned technical improvements so far, but equallyimportant is the quality of service company personnel who helprun the tests. In the last few years, we’ve been getting petroleumengineers doing testing. Before, we might have gotten ex-cementers who were highly motivated but simply didn’t speakthe same language I do, or didn’t understand the tools wellenough to fix problems that might occur.

CRAWFORDService companies have also changed. Flopetrol [now Schlum-berger Wireline & Testing] used to operate separators, get sam-ples and run pressure gauges. They never hooked it all together.Now they have done their theoretical homework and are gettinginto the data analysis business. This has gone a long way towardhelping service company people have a deeper understanding oftheir work.

nThe DataLatch sys-tem allows downholerecording and sur-face readout of pres-sure and tempera-ture data during flowor stimulation. Thetwo components ofthe system are theMSRT MultisensorRecorder/Transmit-ter and the LINCLatched InductiveCoupling tools. TheMSRT tool is a full-bore pressure andtemperature recorder.The LINC tool pro-vides real-time sur-face readout, retrievalof recorded data andcapability to repro-gram the downholerecorder. The LINCtool communicateswith the MSRT toolthrough an inductivecoupling. The systemis shown with thevalve closed, shuttingin formation fluids.

50 Oilfield Review

SIMMONSAnd contracts have changed. A few years ago, we’d work withfive or six service companies simultaneously and have to worryabout whether we could connect Halliburton’s tools withFlopetrol’s. We’re still doing that in some parts of the world, butthe trend is to get involved with only one service company thatcan provide the entire package. This gives me one test supervi-sor on site that I deal with directly. This single chain of com-mand makes information flow more efficiently.

FREYSSWhy did this change come about?

SIMMONSIt boils down to our ability, as a testing group, to educate theexploration and drilling people who set the service companycontracts. Sometimes it’s just the bottom dollar amount. Othertimes, we can influence the decisions when we think there areaspects of a service that outweigh the bottom line. I guess thechange has been that we are better able to offer our input whenselecting a service company. Testing then becomes easier andless cumbersome when we get our way. There is also less fingerpointing if something goes wrong.

Well Test DesignFREYSS

Once you set your testing objectives, you begin to design thetest. How has test design evolved in the last few years?

MACDONALDThere is a trend away from departmental divisions—drilling,geology and testing—and toward a team of geologists, drillersand testers doing the design together. Our testing group hasevolved into an interdisciplinary team, involving petrophysicistsand well test engineers who work closely with the explorationand drilling groups. Once the team sets objectives, the design isdeveloped by well testers and sometimes by drilling engineers.Test execution and analysis are the responsibilities of the welltest engineer.

Cost does dictate test

objectives, but I think

objectives are more

focused because there is

better awareness among

nontesters—manage-

ment, drillers, log ana-

lysts, geophysicists—of

what testing can and

can’t do.

51

FREYSSAnd what is the first step? How do you establish a design?

SIMMONSWe start well test design with simulation studies that give us gen-eral ideas about reservoir properties. Our simulation might tellus that an 8-hour flow won’t be enough, that 15 or 20 hoursmight be needed to see as deep as we want. So our design isspecific on flow and shut-in times, mainly because the computertechnology allows us to plan ahead. The technology also allowsus to change test design midstream. In the past, we often hadfixed ideas about testing—for example, that a DST has a shortflow period, a shut-in, a longer flow period and a longer shut-in.Now, a DST is more broadly defined—any test with a downholeshut-in.

FREYSSThe test design must also include the selection of testing tools.How do you decide which technology is most appropriate? [See“The Nuts and Bolts of Well Testing,” page 14.]

SIMMONSWe use the RFT [Repeat Formation Tester] to get basic formationevaluation in all our exploratory work. Even in the rare well withsevere hole problems, we attempt an RFT run. Often, RFT resultswill cause us not to test an interval further. Other times, RFT datawill present an anomaly that motivates us to test where we hadpreviously decided not to.

CRAWFORDSome people in our company recognize the economy of the RFTtool and would like it to replace all well testing. I don’t subscribeto that. I prefer to use the right tool to get the right answer. Inexploration and infill drilling, RFT data can help identify pres-sure distributions. Most of us would probably agree that it givesa usable estimate of permeability only in certain settings.[General agreement]

FREYSSThe MDT [Modular Formation Dynamics Tester] tool provides astep toward good permeability data, by allowing variation ofdrawdown rate during testing. But when you use the RFT tool,do you try to get the best possible permeability estimate?

MYERSYes. We occasionally have to rely on RFT data for permeability,which is the least desirable way to get that information. Themain limitation of RFT permeability is that its accuracy is limitedby its shallow depth of investigation—on the order of inches,compared with a DST, which can be hundreds to thousands offeet. But because we have used the RFT tool so extensively, mostof our people have seen it used effectively as a pretest tool tohelp define test objectives and test intervals. The RFT measure-ment serves as a kind of first approximation and check. In theToro sandstone in Papua New Guinea, which is highly compart-mentalized, RFT measurements were valuable for determiningthe presence and extent of hydraulic connection between vari-ous intervals in multiple wells. We almost always get goodagreement between reservoir pressure from RFT data and thatextrapolated from pressure transient tests—within 10 to 15 psi.

MACDONALDThe RFT tool is also useful in development wells. We’ve used itto determine whether pressure depletion has occurred.

CLARKIn general, how do you choose between a quartz gauge and astrain gauge?

CRAWFORDWe use quartz gauges most of the time, but find we don’t needthem when the sensitivity of a strain gauge covers the range ofexpected permeabilities and we get an adequate buildup slope.3In an exploration well, my feeling is that unless you knowexactly what you’re doing, you should always use the bestequipment you can afford.

More important than the type of pressure gauge is placing thegauge correctly. This is a problem when DSTs are coupled withTCP [tubing-conveyed perforating]—we can’t get the pressuregauge close to the perforations. In some of our Gulf of Mexicowells that have high permeability, we’re running TCP and there-fore the pressure gauge is 200 feet [61 m] above the perfora-tions. They’re not measuring what we want to measure. WhileTCP is useful, it may require conveying pressure gauges by elec-tric line or slickline to place them where meaningful readingscan be obtained.

FREYSSCan you say how your equipment generally varies in explo-ration, appraisal and development wells?

EL-HALABIIn Venezuela, Corpoven basically uses the same testing string inevery well, TCP, production logging tools, displacement valves,reversing valves and packers. In some wells, where low perme-ability is expected, we go with a bottomhole sampler.

HAIGHOur approach is different. Our equipment depends on ourobjectives. For simple objectives, such as fluid identification, inland-based operations in Alberta [Canada] there’s no need to goto anything more sophisticated than a simple openhole test usinga device like the MFE [Multiflow Evaluator tool] string (next page).If we want more—if we want to test, acidize and retest rightaway—we’d probably choose a PCT [Pressure Control Tester]string, as opposed to an MFE string.

For clients drilling offshore exploration wells, we’ve devel-oped a simple PCT string with a surface readout. This providesan understanding of skin that helps with planning acidization.

MACDONALDIn many wells, we tend to run production logs with the DST, par-ticularly where we have done some stimulation. Most impor-tantly, the production log determines the distribution of contribu-tions to flow, especially with a long perforated interval. It alsogives surface readout of downhole pressure.

EL-HALABIWe have another approach to the multiple reservoirproblem—selective firing. We shoot in one zone, test it, thenshoot the one above and test both zones together. Sometimes wedivide the reservoir into three zones, and shoot and test eachseparately. This is perfect in settings where safety concerns pre-clude going in the hole with a wireline.

FREYSSDo you do layered reservoir testing during the cased-hole DST,or do you attempt to first do a complete test to understand whatcontributions are coming from where?

MYERSMost of our layered tests are on production wells, with no rig onlocation. We just run a production log followed by a bottomholepressure buildup. The initial production log gives us some ideaof wellbore phase segregation. Layered reservoir testing wouldallow us to refine how to subdivide the zone into layers.

FREYSSWith the new versatility that comes with cased-hole DSTs—suchas the ability to spot acid, stimulate and test the string—are youseeing more use of DST to optimize completions?

MACDONALDNot necessarily from DST, but we are seeing an increase in earlyproduction testing of development wells, using pressure transientanalysis to determine whether additional completion work isrequired—acidizing, hydrofracing or other kinds of stimulation.We have carried out testing programs designed to optimize com-pletion techniques for various formations.

HAIGHIf the well test objective is determination of completion effi-ciency, you’re probably somewhat advanced in field develop-ment. Therefore, you’re also going to want to understand reser-voir discontinuities farther from the well. This means testing forlonger than you would just to investigate the near wellbore.

CLARKCan you design a test to evaluate sand production?

EL-HALABIUsually, we go by erosion of surface equipment. Sometimes,sand won’t be visible in samples in the field, but will be appar-ent when we look at samples in the laboratory. When we haveexcessive sand production, we just reduce choke size.

52 Oilfield Review

HAIGHBeing smart about how you perforate can help prevent sanding,at least during testing. In the Beaufort Sea [Canada], we did thisby perforating with a slight underbalance, a high shot densityand deep-penetrating charges.

MYERSMobil has used a sand detection device that enables us to chokeback the well until the probe reports a stable production rate.Using this, we can produce through the winter, and in the sum-mer, when demand drops, shut down the well and gravel pack.The sand detection device, made in Norway, is basically anacoustic transducer that clamps on the outside of the flow lineuphole. It measures acoustic emissions at the outer surface of thepipe wall that tell the amount of sand produced with the oil, gasor multiphase mixture. The software allows you to vary thereport, for example, as pounds of sand per thousand barrels ofoil or grams of sand per second.4

nThe MFE Multiflow Evaluator tool is the main downhole valve controlling flow in a typical openhole test string. It is operated bypipe reciprocation and may include a choke and, as shown here, a sample chamber.

As the tool is run in under tension (left) the sample chamber is closed. When the tool hits bottom, the slow application of weightopens it, permitting the well to flow (middle). The opening is metered by the hydraulic delay system. The tool can be closed, and theflow stopped, almost immediately by pulling up on the tool. It cannot be maintained in tension, however, or a bypass valve willopen. The index system at the top of the tool provides a lock that keeps the tool in an intermediate closed position when tension isreleased (right). The tool can be reopened by pulling up again.

FREYSSWe’ve talked mostly about cased-hole DST. What remains therole for openhole DST?

MYERSIt’s been many years since our group has conducted an open-hole test with an openhole packer. Our openhole testing is con-fined mainly to barefoot testing where we stay up inside the lineror casing with a regular packer to test the openhole section below.

53April 1992

3. A stable, constant slope on a pressure vs. log time plot indicates infinite-acting radialflow, which is essential for permeability estimation. Today, this diagnosis is made ona plot of pressure derivative vs. log of time.

4. Folkestad T and Mylvaganam KS: “Acoustic Measurements Detect Sand in North SeaFlow Lines,” Oil and Gas Journal 88, no. 35 (August 27, 1990): 33-39.

Free fall

Ports open

Inner mandrel

Spline

Spline sleeve

Bearings

Index pin

Brass valve

Valve spring

Oil chamber

Upper packing

Flow ports

Lower packing

Top sub(optionalchoke)

Indexsystem

Hydraulicdelay

Valve andsampler Sample chamber

Splines passthrough splinesleeve

Portsclosed

Tool closed(tension)

Tool open(compression)

Tool closed(compression)

Fluidsample

Mandrel

Spline

IndexSlot

Bearings

Housing

(Compression)tool open

(Compression)tool closed

(Tension)tool closed

HAIGHIn Canada we do many openhole DSTs. There are many reasonsfor this, but the two main ones are that the tools are availableand that we have reservoirs of low productivity—typically under500 barrels per day. Flow rates are much lower than elsewhereand, in general, if things mess up, the well isn’t going to getaway from you. The tests are simple: either you get oil in thepipe or you don’t. We don’t use pressure controlled tools, justtools controlled by picking up and setting down the pipe.

EL-HALABIHow hot do your wells get?

HAIGHAbout 70°F [21°C] for shallow wells, 200°F [93°C] for deeperwells. In the latter, we wouldn’t do openhole testing. But in gen-eral, we’re cool compared to the rest of the world.

SIMMONSIn Chevron, we’ve tested at up to 350°F [177°C] in cased hole,recorded on a memory gauge. This is pushing the limits of gaugetechnology. But once you get above 320°F [160°C], it’s hot andwhether it’s 325°F or 340°F [163°C or 171°C] doesn’t makemuch difference.

FREYSSDownhole testing equipment has two temperature-sensitivecomponents: lithium batteries and electronics. In hot wells, doyou prefer to use a wireline gauge, leave it for a few hours andretrieve it, rather than use a downhole recording gauge?

SIMMONSWe do both. We would like to do more electric line work, butour drilling department restricts use of electric line for safety rea-sons. This is not only in high-temperature and high-pressureenvironments, but also on floating rigs or gas wells. To combatthis resistance, we are constantly trying to educate our opera-tions people that if it’s OK to drill, it’s OK to test.

MACDONALDOur philosophy is to keep everything as simple as possible with-out compromising our objectives. Tools are more reliable today,and we don’t have any problem running wireline for sampling orpressure readings. In general, we’re not big on surface readout.

Don’t get me wrong—I’m not against surface readout. It’svaluable in many situations, but not in every one. I think it has aplace when you’re dealing with an extended time test—but itbecomes more costly the longer you go. If you can make aneducated decision any time during testing that might cause youto terminate the test early, you can save a considerable amountof money.

SIMMONSWe find surface readout devices valuable in the test-frac-retestscenario. In these cases, unusually long flow/buildup times maybe required to reach the end of the fracture-dominated linearflow period. Surface readout devices allow us to monitor thetransient’s progress in real time, and therefore minimize the pos-sibility of having to retest the well to satisfy test objectives.

FREYSSA part of testing we’ve discussed only in passing is fluid sam-pling. Gary, can you summarize how that has changed for youin the last few years?

CRAWFORDIn the past, we always took surface and bottomhole samples andultimately threw out the bottomhole samples. The bottomholesamples had the wrong bubblepoint, the well wasn’t condi-tioned right or we might have lost pressure on sample retrieval.Today, however, we’re working in complex fluid systems andbottomhole sampling becomes more important. Sampling is liketaking pressure readings: assuming stable flow, the closer we areto the reservoir, the better the sample.

54 Oilfield Review

Usually, we go by erosion of surface equipment[to evaluate sand production]. Sometimes, sandwon’t be visible in the samples in the field, butwill be apparent when we look at samples in thelaboratory.

If the well test objective is determination of completion efficiency, you’re proba-

bly somewhat advanced in field development. Therefore, you’re also going to

want to understand reservoir discontinuities farther from the well.

HAIGHAn often overlooked key to good sampling is well conditioning,which is difficult if the oil zone is near bubblepoint. In mostwells, nobody wants to take the trouble to do it right. A biggersampling problem for us in Canada is sour reservoirs, from 35%to 95% H2S. One operator, with 80% H2S, is circulating downan oil solution that absorbs H2S, which is then stripped out atsurface and recovered as sulfur. The circulation of oil preventssulfur deposition downhole.

Quality Assurance and Test ControlHAIGH

What do your companies do for quality control, for instance, toensure that downhole gauges are calibrated prior to going in thehole? I ask because we had a well test in which the GOR indi-cated by the separator and bottomhole samples didn’t match oreven come close. We were off by a factor of two. We found thatthe engineer on site didn’t verify the size of the orifice plate inthe meter.5 Since then, we have done on-site calibration, such asmeasuring the orifice plate and choke sizes in the field, inspec-tion of tools in the shop, checking tool connections, metallurgy,function testing, pressure testing on the catwalk before pickingup the tools and pre- and post-test calibration of downhole pres-sure gauges. Once we started doing this, many data problemsdisappeared. Has anyone else gone this route?

MACDONALDChecklists are becoming standard, whether they’re ours or theservice company’s. A major change that has helped data qualityis the tendency to go with one service company. This gives us asingle control point that leads to better overall quality control.

SIMMONSOften, things that go wrong are simple to address but aren’taddressed properly—is the right orifice plate installed? Is thechoke size actually what it is reported to be? These are reasonsto have a test engineer on location.

FREYSSHow do you validate the data? How do you check that the dataare of good quality and sufficient to permit full interpretation?

MACDONALDThe biggest advance in this respect is how decisions are madeon site. In the past, test objectives were set by a small group, andit was sometimes difficult to come up with a conclusive decisionon site. Today, our objectives are set jointly by explorers, opera-tions people and well testers. The well test engineer decides howlong the test should be, validates data and does the initial inter-pretation. And today the well test engineer has a lot of support tocall on, if needed, as a result of modern communication technol-ogy. This has improved the performance of our testing programs.

5. The relationship between the orifice size and measured gas rate is

in which Q is gas flow rate, C is a coefficient, P is gas pressure and ∆P is differential pressure across the metering orifice.

April 1992

Q = C P × ∆ P ,

CLARKHas the ability to transmit data from the wellsite almost in realtime affected rig-site decision making?

MACDONALDNo. Within Conoco, the individual on the rig is capable of doinginitial interpretation. If a special difficulty arises, he can fax datato pressure transient experts in our Houston office. But we donot routinely transmit data to headquarters. The guy on the rigdoes the analysis and decides what to do next.

SIMMONSWe do the same thing. We always validate data on the rig anddo at least cursory analysis. We seldom rely on the service com-pany for the only interpretation.[General agreement]

55

Special Cases: Slim Hole, Horizontal HoleCLARK

Testing of horizontal wells often raises more questions than itanswers. What have we learned about horizontal well testing?

CRAWFORDIn the last few years, the main thing we learned is that we arenot testing them correctly. The problem is, we can’t get usefulinformation in the typical 24-hour period. It takes a long time totest a horizontal well—perhaps weeks. We don’t know the out-side limit of that envelope. Perhaps we could test while flowinginstead of shut-in. But it’s hard to get good data during a draw-down test because the well is cleaning up and we cannot mea-sure the rate variations precisely—drawdown tests aren’t verysuccessful, even in vertical wells. This leaves the buildup as theonly practical test, and in horizontal wells, it just takes longerand thus costs more than most people are willing to pay.

Another problem, at least in developed fields, is that we oftencan’t identify all the flow regimes because producing wells inter-fere with transient testing, which precludes testing.

SIMMONSTesting theory for horizontal wells is in place—we understandthe transient model by which a horizontal well should perform.The problem is getting enough data from a given well to com-pare that well with the model. We can compare five minute’sworth of data to our model, but the answer is not unique.Twenty other models might work as well.

CRAWFORDOf paramount importance in planning a horizontal well test isan attempt to identify early radial flow, which requires a down-hole shut-in [see “Testing Design and Analysis,” page 28]. Thishas been one cause of failure of horizontal well tests, becausethey have been done on production wells in which we’ve haddifficulty with downhole shut-in devices. Downhole shut-in isour only hope for minimizing the effect of wellbore storage.

HAIGHIn Canada, we have seen many horizontal wells that havefailed—no improvement in production, if any production at all,compared to a vertical well. The reason for failure is not usuallyunderstood, but it may be the wrong application of the technol-ogy. You need good vertical permeability for a horizontal well to work.

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6. A macaroni string is tubing or pipe string of 3/4-in to 1-in diameter. It is also a tubingstring inside a tubing string.

CRAWFORDSo the question is: What can testing tell you about vertical per-meability? You can drill a vertical section, perf the top part, test itand identify a partial penetration effect. This gives you someidea of the vertical permeability over a wide area, not just in thefew meters around the well. If it is high enough, you back off,kick off and go horizontal. This approach can add significantlyto the cost of a horizontal well. Vertical interference testing costseven more.

FREYSSI’d like to finish with a discussion on testing of slim holes. Therehas been a lot of talk about slim hole drilling. What are theneeds for dynamic evaluation in these holes?

MYERSToday, we have only a few options for slim hole testing andthese have limitations. We use a macaroni string6 or set a retriev-able packer way above the openhole interval and contend withwellbore storage. A third option is to set the packer in larger holeand use it to hang extended tubing into the openhole section.

MACDONALDPeople can talk about how much they save by drilling slimholes. But we have to remember we’re drilling wells to obtaindata to evaluate a potential play. So slim holes may have a placein wildcat territory. Perhaps we’ll drill a few slim holes to obtainsome information, come back and drill one that we can test. Butwe have to remember that sometimes slim hole is not going togive us the information we need, even though it will be initiallycheaper. —JMK

Oilfield Review

Testing theory for horizontal wells is in place—we understand the transient

model by which a horizontal well should perform. The problem is getting

enough data from a given well to compare that well with the model.

Moderator’s Summary

Henri FreyssHouston, Texas, USA

In today’s tough economic climate, the oil industryis focusing more on increasing profitability in newand existing fields, than on exploration. Thisresults in two strategies:

One is increasing well productivity—accelerat-ing the financial return on the capital invested todevelop and produce reservoirs. The other isincreasing ultimate recovery—achieved by prop-erly managing fluid flow inside the reservoir, usingthe available drive energy as efficiently as possible.

The common denominator is fluid flow manage-ment. This includes facilitating oil flow toward pro-ducing wells, helping gas segregate to the uppersections of the accumulation to act as a drivingpiston and monitoring injected fluids to optimizevertical conformity and areal sweep efficiency.

The key measurements are production loggingfor describing flow in the immediate vicinity ofwells and transient well testing for exploring thewhole drainage volume of a well. This roundtable,and other articles in this issue of Oilfield Review,concentrates on transient testing. Recently, welltesting has experienced major innovation andimprovement. Here are some of the leadingachievements and challenges:• Maintenance of an excellent safety record—

Despite increasingly high pressures and flowrates, the safety record has continued to beexcellent. Regulatory agencies, operators andservice companies have cooperated to guaranteemaximum safety during testing operations. Thishas been achieved with thorough specificationsfor equipment, pretest pressure testing of allcomponents, unambiguous field procedures andin-depth training at all levels of responsibility.

• New pressure gauge technology—Transient test-ing has been transformed by breakthroughs inpressure gauge technology. Electronic gaugeshave replaced the rugged but low-resolutionAmerada gauge and new quartz sensors, rela-tively unaffected by large temperature and pres-sure shocks, boast a resolution better than 0.01psi and a repeatability of the order of 1 psi.These are packaged in recorders with long lifeand small diameter (11/4-in.) at cost-effectiveprices.

57April 1992

The new DataLatch system (page 50) com-bines downhole pressure recording—during flowperiods when data are not always needed at sur-face—and a link enabling data downloading andreal-time surface readout of downhole pressureduring buildup when data at surface are crucial.

• Enhanced data validation and analysis—Betterpressure data obtained at shorter time intervalshave allowed development of a new methodol-ogy for well test interpretation. This methodol-ogy is based on diagnostic plots, such as thelog-log pressure derivative-versus-time plot,that helps identify the predominant flow regimesduring a test and allows for real-time monitoringof the operation.

Use of small computers at the wellsite tomanage the data permits monitoring of testprogress to validate the quality of the data inreal time and to terminate the test as soon as ithas run its course.

In the analysis stage, greater use is beingmade of complex analytical models to provideinformation about the structure of the flow insidethe reservoir, about the boundaries of the vol-ume drained by the well and finally about thepredominant energy source driving production.

• New DST systems—Expanded reliability and ver-satility of DST systems have resulted in muchmore cased-hole DST testing, especially off-shore. Multicycle circulating valves allowsophisticated operations such as pressure test-ing the string once the packer is landed, displac-ing fluid inside the tubing/drillpipe before thetest, circulating produced fluid out after the testand spotting cleaning or stimulation fluids intothe formation. The introduction of the electrohy-draulic IRIS Intelligent Remote ImplementationSystem equipment (see “The Nuts and Bolts ofWell Testing, page 18) is another step forward inreliability, versatility and operational efficiency.

• New cost-effective testing methods—For devel-opment wells, where conventional well testing isoften not cost-effective, new methods have beendeveloped that allow appraisal of importantdynamic formation parameters.

The first is impulse testing, a method of mea-suring completion efficiency during tubing-con-veyed perforating. The second is layered reser-voir testing, in which simultaneous recording ofdownhole pressure and flow rates versus time at

different depths sheds light on the dynamicbehavior of individual layers.

Despite this progress, there are plenty ofchallenges remaining. The most important are:

• Clean burning of fluids produced during testing—Initially, the industry was apprehensive aboutburning crude oil offshore. The first generationburner was designed to achieve incompletecombustion—with a small flame, minimal gen-eration of heat and heavy smoke. Once burnerswere accepted, the smoke was removed byinjecting water into the flame resulting in aclean, very hot burn. Developments continue,notably to improve the monitoring of the processand of the flame, ensuring that only clean andreasonably nonpolluting, fully oxydized productsare released.

• Lower flow rates—The volume of reservoirinvestigated by a well test theoretically dependson the duration of the test, not on flow rate. Inreality, pressure gauge resolution imposes alower limit on flow rate. Increasing gauge reso-lution could lead to a decrease in flow rates thatcould be tested, greatly simplifying the logisticsof offshore well testing.

• Surface multiphase flow measurements—Tradi-tionally, separators are required during a welltest to separate the various phases so their indi-vidual flow rates can be measured. Muchresearch today concentrates on devising a sur-face-metering system that would not requirephase separation.

• Horizontal wells—Horizontal wells are playing amajor role in the quest to improve productivityand ultimate recovery. These wells haverevealed the high degree of lateral heterogeneityin reservoirs and the importance of an often-neglected dynamic parameter—effective verticalpermeability. While we have analytical solutionsfor well tests in an increasing selection of hori-zontal configurations, day-to-day analysis ofhorizontal well tests remains a tough challenge.

The rapid pace of evolution in well testing indi-cates that these technological challenges will bemet successfully. The rate of technological devel-opment may even accelerate. Spurring change is anew understanding that joint development pro-grams between operator and service company canbring new ideas to the field much faster than before.