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Summary Evaluation methods have been developed to detect cases of tubing annulus communication. Temperature, spinner and noise logs, as well as fluid level detection equipment, are used under a variety of flow conditions. Stepwise procedures are provided. Introduction Production in the Prudhoe Bay Unit Western Operating Area (WOA) began in June 1977. Wells now flow naturally or with the aid ofgas lift. Rates vary from 100 to 10,000 BOPD or more and gas oil ratios (GOR) from 60010,000 scfSTB. Water cuts have in creased mainly in the waterflood areas and can approach 100%. The combination of water and 12 % carbon dioxide in the dissolved solu tion gas forms carbonic acid, corroding tubulars despite corrosion inhibition treatments. A typical completion is shown in Fig. 1. Tub ing sizes range from 312 to 7. In the early years offield life few workovers were required. Most of these were to replace defective packers and thermocase tubing. An increasing number of mechanical failures of tubular components as well as worsening corrosivity of produced fluids has significantly increased the occurrences of tubing annulus communication and corresponding workover requirements. In 19881989, 50 cases of tubing annulus communication were found in the WOA. Of these, 5 were permanently repaired with wireline techniques and 3 were temporarily repaired until a workover could be implemented. The remaining 42 wells were shut in and worked over without attempt ing remedial measures. This paper discusses methods used at Prudhoe Bay for identifying problem wells and determining the exact location of the leak in natu rally flowing, gas lifted, and injection wells.
Methods of Detecting and Locating Tubing and Packer Leaks in the Western Operating Area of the Prudhoe Bay Field C.M Michel, SPE, BP Exploration Summary Evaluation methods have been developed to detect cases of tubing/ annulus communication Temperature, spinner and noise logs, as well as fluid level detection equipment, are used under a variety of flow conditions Step-wise procedures are provided Introduction Production in the Prudhoe Bay Unit Western Operating Area (WOA) began in June 1977 Wells now flow naturally or with the aid of gas lift Rates vary from 100 to 10,000 BOPD or more and gas/ oil ratios (GOR) from 600-10,000 scf/STB Water cuts have increased mainly in the waterflood areas and can approach 100% The combination of water and 12 % carbon dioxide in the dissolved solution gas forms carbonic acid, corroding tubulars despite corrosion inhibition treatments A typical completion is shown in Fig Tubing sizes range from 3- 1/2" to 7" In the early years offield life few workovers were required Most of these were to replace defective packers and thermocase tubing An increasing number of mechanical failures of tubular components as well as worsening corrosivity of produced fluids has significantly increased the occurrences of tubing - annulus communication and corresponding workover requirements In 1988-1989, 50 cases of tubing - annulus communication were found in the WOA Of these, were permanently repaired with wireline techniques and were temporarily repaired until a workover could be implemented The remaining 42 wells were shut in and worked over without attempting remedial measures This paper discusses methods used at Prudhoe Bay for identifying problem wells and determining the exact location of the leak in naturally flowing, gas lifted, and injection wells Traditional Methods for Leak Detection Numerous articles are available related to temperature logging for production logging purposes.l· Noise logging articles have focused on production logging or finding leaks behind casing ,4 This work is useful to the extent that the basic concepts of tool response still apply in tubing-annulus communication troubleshooting The technical literature on identifying tubing leaks consists mostly of mechanical devices run on wireline The devices form a seal to the tubing wall and are pumped down to the leak Two such examples are provided in the references ,6 It is unlikely these devices would work in North Slope wells due to the restriction at the sub surface safety valve Leak Detection Methods at Prudhoe Bay Leak determination techniques for Prudhoe Bay wells have been developed which primarily employ electric line logging The strategy used depends on the condition of the well and whether the well is naturally flowing, on gas lift, or is an injector Each case is discussed individually The underlying strategy in almost all cases is to obtain baseline results with the well in near static thermal equilibrium, then alter conditions to induce temperature and time transients Copyright 1995 Society of Petroleum Engineers Original SPE manuscript received for review April7, 1991 Revised manuscript received Nov, 13 1992 Paper accepted for publication Dec 6, 1994 Paper (SPE 21727) first presented at the 1991 SPE Production Operations Symposium held in Oklahoma City, April 7-9 124 Tool Selection The optimal tool string depends in part on the magnitude of the leak At the lower range of leak rates (or leaks behind another string of pipe) the noise log is often the most sensitive and the best tool for pinpointing a leak The temperature log works over a broad range of leak rates, butis usually not as sensitive as the noise log A spinner can be used for rates above the detection limit of the tool (usually about feet/minute velocity) A philosophical approach to tool selection is provided in Fig Naturally Flowing Well Leak Detection Annulus pressure readings are taken on a daily basis Any unexplained increase in annulus pressure is cause for investigation An attempt is made to bleed off the pressure The initial and final pressures along with the amount and type of fluid bled is documented If the pressure returns, then troubleshooting efforts begin Leak Detection Method An acoustic sounding of the liquid level in the annulus is the first step in leak detection After non-gas lift wells are completed they are left with a full liquid column in the annulus Assuming no wireline work has been subsequently done to allow wellbore gas to enter the annulus since the completion, a liquid level significantly below the wellhead is further confirmation of a leak Further, because the leak must be at or below the liquid level, the level may provide an indication of the location of the leak In one case the entire annular fluid volume to the packer was voided Determination of the Leak Rate by the Non-Ideal Gas Law The rate of increase in the annulus pressure alone is not sufficient in determining the severity of the leak as it is a function of the leak rate and the compressibilty of the annular fluids For example, even a very slow transfer of wellbore fluids into a liquid-packed annulus results in a dramatic increase in annulus pressure On the other hand, the pressure of an annulus having a deep liquid level responds deceptively slow to a significant influx of wellbore fluids, With the well shut-in, the annulus pressure is bled after noting the initial fluid level For low GOR wells: the fluid entering the well is mostly liquid The rise in annulus fluid level with time can be converted to barrels per minute (BPM) For high GOR wells: mostly gas enters the annulus and the liquid level remains fairly constant The system can be modeled as a concentric cylinder of constant volume V bounded by the wellhead at the top, the liquid level at the bottom, the tubing on the inner radius, and the casing on the outer radius The influx of gas into the inner annulus from initial to final conditions can be quantified by using the non-ideal gas law: _ 188 (P/zr- P/zi)V Qleak (460 + T) ~t with P expressed in psi, V in barrels, ~t in minutes, T in OF, and Qleak in standard cubic feet per minute (SCFM) Annular flow leak determination method Gas flashing across the leak provides Joule-Thompson effect cooling easily detectable on the temperature log This process has the advantage of being consistent with the conditions under which the leak is known to occur: that is, hydrocarbons flowing from the tubing to annulus side Based on experience to date, approximately 10 SCFM is considered the minimum rate detectable by electric line logging methods Leaks near surface where higher differential pressure can be established, are more pronounced SPE Production & Facilities, May 1995 ALL DEPTHS ARE MEASURED DEPTHS UNLESS INDICATED OTHERWISE J-24 II) II) UJ Z UJ > SUBSURFACE SAFETY VALVE 2087 FEET 13-3/8", 72#/FT 2701 4-_ _ TO 15 GAS LIFT i= u UJ LL LL UJ J a a I- MANDRELS 4-1/2" SLIDING SLEEVE 10420 FT PBR 9-5/8" PACKER 10516 TOP OF 7" LINER 10557 Fig 2-Philosophical view of tool selection An example of the temperature log while flowing the annulus is shown in Fig 4-1/2" "X" NIPPLE 4-1/2" "XN" NIPPLE 9-5/8" 47#/FT 10843 PERFORATIONS 11325-11355 (8890-8913 TVD) 7", 26#/FT 11700 Fig 1-Typical Prudhoe Bay WOA well completion Prior to electric-line logging, tubing and annulus are both shut in for at least eight hours This allows the wellbore to approach static thermal equilibrium for baseline conditions Electric line is rigged up and a continuous temperature log made from surface to a point at least 200 feet below the tubing tail Baseline data may also be acquired with the noise tool, which is included on the tool string if the leakage rate is low and ambiguity anticipated with the temperature logging alone.* The tool is then positioned at a point at least 200 feet below the suspected leak while monitoring temperature The annulus is bled off in 400 psi stages, interspersed with temperature passes After the initial bleed off, one expects to see increasing temperature at the stationary positioning point below the leak This is due to warmer (deeper) wellbore liquids gradually flowing upwards past the tool and toward the leak Thus, when the "dynamic" (after bleed off) temperature passes are made they show progressively warmer temperatures below the leak This is usually on the order of a 0.25 - 2°F The dynamic passes diverge from being warmer than the static pass below the leak, to being colder near the leak where JouleThompson and/or latent heat of vaporization effects are occurring For deep leaks where low tubing - annulus ilp was induced, this cooling effect may be only 0.5 to oF For shallow leaks with greater ilp the effect will be far greater Above the leak, the dynamic temperature passes remain progressively cooler than the static pass as the cooled liquids travel up the annulus At some distance above the leak, typically 200-300 feet, the dynamic passes usually approach the static pass temperatures as thermal exchange with the surrounding formation dominates The intermediate temperature passes while bleeding offthe annulus in stages help pinpoint and confirm the leak • A discussion of noise logging techniques as it relates to leak determination is given in the appendix SPE Production & Facilities, May 1995 INCREASING LEAK RATE Annular injection leak determination method For wells that leak at high liquid rates (greater than 0.25 BPM), an alternative method is to pump a liquid down the annulus and through the leak A plug is set first in the tubing tail If pumping can be sustained down the annulus with barrel for barrel returns up the tubing, then the packer is ruled out as the communication problem Compared to the baseline pass, the dynamic passes will exhibit the following behavior: 1) Identical temperature below the leak (static fluid) 2) A temperature spike at the leak due to friction heating (unless no restriction exists) 3) Either cooler or warmer temperature above the leak, depending on the amount of friction heating, the pump rate, and temperature of fluid pumped (relative to original temperature of fluids downhole) A temperature log from troubleshooting a large leak by pumping down the annulus is shown in Fig 4_ For wells with packer failures, there will be no returns up the tubing Progressively cooler temperatures will be measured from surface to the plug depth The troubleshooting can be done without initially setting a plug in the tailpipe, but can be more difficult If sufficient annular injection rate is obtained such that a high pressure drop is developed across the leak, then friction heating is detected Alternatively, if the leak rate is sufficient such that the velocity in the pipe exceeds approximately feet/minute, a spinner tool can aid in detection The annular flow method is preferred to the annular injection method, since it duplicates conditions under which the well is known to leak No plug is necessary, and plugs are best avoided due to evaluation complications if they leak and due to potential removal problems if they become stuck ARCO Alaska, Inc (the operator of the Eastern Operating Area at Prudhoe Bay), however, has reported successes using the annular injection method at rates down to 0.25 gallons per minute'? Leak Detection in Gas Lifted Wells Gas lift wells are the easiest cases to troubleshoot The investigation is normally completed with the well flowing at steady-state conditions on gas lift As a tubing leak develops, lift gas will pass through the leak A decrease in casing pressure is usually experienced This is due to 1) an increase in the total annulus-to-tubing flow area and 2) the shallower "lifting point" if the leak develops above the normal lifting point For the latter locations, a decrease in gross fluid production associated with inefficient gas lift operation is also common Table provides an example An acoustic fluid level measurement in the annulus with the well on lift is an important first step in troubleshooting Various scenarios with the corresponding acoustic sounding results are as follows: 1) Large hole, shallow leak: The liquid level can be just below the leak, since little or no differential pressure can be developed across the leak to unload annular fluids (which can accumulate after a shutin period) The actual distance below the leak of the annulus fluid level will be equal to the pressure drop across the leak divided by the 125 TEMPERATURF DEG F 9200 TEMPERATURF DEG F ,, ,, , 210 215 220 225 140 145 150 15S 8300 BASELINE PASS 9300 - 8400 - t 9400 - 9500 - DEJYfH IN Ff GEOTHERMAL GRADIENT 8500 - ,, ,, \ t t 9600 - LEAKIt\G GAS UFT MANDREL 9700 - DYNAMIC PASS 9800 - t \ 8600 - LEAKING GAS LIFT MA:-.JDREL DEJYfH t 1:-': Ff 8700 - t GEOTHERMAL GRADIENT 8800 - 8900 - Fig 3-ldentification of tubing leak using the annular flow method Fig 4-ldentification of tubing leak using the annular injection method difference in the casing gas gradient and the flowing tubing gradient below the leak If the leak is higher than the shut-in tubing liquid level, then the annulus may stay dry, even to the bottom operating gas lift valve 2) Small hole, shallow leak: The annular fluid level can still be at the normal lifting point (There must be significant pressure drop across the leak for this situation to occur) 3) Leak below the normal lifting point, small operating gas lift valve port size: The annulus will have unloaded below the normal lifting point all the way to the leak 4) Leak below the normal lifting point, large operating gas lift valve port size: Because virtually no pressure drop is taken across the gas lift valve, the fluid will not unload significantly below this point Ifthis is suspected a smaller port size or dummy gas lift valve should be installed In most cases a suspected leak is easily verified by temperature logging The tool string used consists of a temperature tool and casing collar log A lift gas rate of over MMscflD, or enough to ensure a significant pressure drop across the leak, is preferred uncertainty remains Examples of tubing and packer leaks are shown as Figs and 6, respectively A screening procedure similar to the above has been adopted as part of production logging work The well bore temperature is continually recorded while running in the hole This information is also useful for gas lift valve redesign and troubleshooting Leak determination method A log of the entire tubing string to a point 200 feet below the tailpipe is made Where the leak is encountered, a general shift in the temperature gradient is noted The gas entry results in a flowing tubing temperature decrease above the leak anywhere from 0.25 to degrees, depending on lift gas rate, fluid rates and composition, and hole size Logging out through the tailpipe is done to investigate any leaks at the packer, which then show up as a cooling at the tubing tail However, logging much below the annular liquid level is unnecessary since no lift gas could be encountered Any suspicious anomalies are repeated The lift gas can also be shut-in and a "baseline" pass made without gas lift if any 126 Injection Well Leak Detection Injection well leaks usually present a particular challenge Typically, the leak rate is low Because of the higher bottomhole pressure (compared to producing wells) even a small leak can over time, cause an annulus pressure approaching the wellhead injection pressure The leaks can sometimes be temperature sensitive, leaking only while the well is on injection with warm fluids TABLE 1-EFFECT ON CASING PRESSURE AND PRODUCTION RATE OF A HOLE DEVELOPING IN A TUBING STRING Test Date Well M-10 Gross Fluid Rate (BLPD) Watercut (%) Lift Gas Rate 1/3/88 1/26/88 2/4/88 2/18/88 3/22/88 4/6/88 5/16/88 7200 6500 6200 5800 5800 5800 5800 62 63 63 62 63 63 63 3.7 4.1 4.1 4.1 4.1 4.1 4.1 (MMscf/D) Casing Pressure (psi) 1785 1570 1320 1235 1240 1210 1070 SPE Production & Facilities May 1995 9850 _ TEMPFRATURE DEG F TEMPIDTURf, DEG F 222 114 12 228 GAS LIFT 10100- MANDREL 8z (f) Z r 10150- o 9900 - § c;") t SLIDING SLEEVE ~ nn 9950 - (f) R r 10250- GAS LIFT MANDREL DEPTH I~ IT DOWN DIP AT HOLE ~ LEAKING PACKER lOCOO- r m < m r ~ (") o c ~ R C r ~ o r DFPTH !NIT m < m r 10050- (f) tn I o I 10100- 10350- 10150- 10400- Fig 5-E-line and acoustic fluid level response for a gas lift well with tubing leak Fig 6-Temperature log and acoustic fluid level sounding on a gas lift well with a packer failure Injection wells at Prudhoe Bay are either water, water-alternating-miscible gas (WAG), or gas Many injection wells are converted producers Wells experiencing little or no communication problems on water injection can have a much greater communication problem on gas injection Thus, troubleshooting of these wells is done while on the gas injection cycle if possible Monitoring, problem detection, and leak quantification processes for injection wells is analogous to those described for naturally flowing production wells multiple sets made while running the tool into the hole injectivity was zero and no annular returns were apparent After setting the tool below the PBR, slow but definitive leak injectivity was apparent Gas Injection Well Leak Detection For wells with significant leaks an identical strategy to that used for naturally flowing producing wells is used: a baseline temperature pass under near static conditions is made, followed by bleeding the annulus in stages interspersed with dynamic temperature passes In one (extreme) example, a well with a leak at 1,021 feet exhibited 56 degrees of cooling compared to the baseline pass Most other wells have not been as easy to identify because the leaks were deeper and slower For troubleshooting these wells a noise tool is usually included in the tool string If the above method is unsuccessful, a plug is set in the tubing tail The annulus is allowed to reach an equilibrium pressure The tubing is pressurized with gas, and the annulus pressure is bled off If the annulus pressure returns to its original value and the tubing pressure does not change, a packer leak is indicated If tubing pressure drops as annulus pressure increases, then the leak is somewhere in the tubing string If the leak is in the tubing string, then a slug of liquid is pumped into the tubing and allowed to fall Once in place, its top can be verified with an acoustic liquid level device The tubing is pressurized with gas and then shut in If technique is successful, the liquid level will slowly move to the location of the leak and stop The exact location of the liquid top can be verified by using a fluid identification device such as a density or capacitance type electric line tool Water Injection Well Leak Detection A plug can be set in the tail pipe and pumping done down the tubing or annulus, similar to the method described for naturally flowing producing wells In one 7" completion with no nipple profiles that leaked at a very slow rate, a modified Baker-Lynes inflatable packer set with coiled tubing was used to confirm a leak at the PBR (The poppet valve was removed allowing multiple sets with the same packer.) During the SPE Production & Facilities, May 1995 Recommendations I) Do not rely heavily on hydrostatic head calculations to determine the leak location If anything, annulus pressure tends to be higher than what would be calculated for a given depth of tubing/annulus communication 2) Prior to investigating with electric-line logging, attempt to duplicate the conditions under which the logging will be done For example, shut the well in first for 6-8 hours Then bleed off some annulus pressure and note the rate of annular pressure/liquid level build-up Some leaks are thermally related and cease after the well is shut in (necessary for a baseline pass) 3) There are numerous individual ways to pinpoint the leak location, many of which involve combinations of the aforementioned techniques It is important to determine ahead of time what type of log response is anticipated This can impact the tools to be selected and the sequence of actions planned 4) In most cases it is best to use the reservoir as the pressure source (annular flow method) rather than pumping liquid down the annulus (annular injection method) 5) When possible, get baseline measurements prior to inducing tubing/annulus communication This will provide a greater degree of confidence in the results Nomenclature Pi = Pf= Zi = Zf= T= V= L'l.t = Qleak = initial annulus pressure, psi final annulus pressure, psi Z factor, initial conditions Z factor, final conditions annulus temperature, OF volume of annulus from wellhead to liquid level, bbls elapsed time in minutes leak rate in standard cubic feet per minute (SCFM) Acknowledgments The contribution of the members of the BP Exploration (Alaska) North Slope Production Engineering department are gratefully acknowledged Julie Heusser and David Smith of ARCO Alaska, Inc provided me with further insights and examples 127 Mlll.I\I ()L· I~ (WG S(JIJ.t:) HICH 't~ NOISJ:: ~IUQUI::J"l:Y IY\"'DWIUlH ~ (SCHI.UMII~R(;t:I(1 Fig 7-Noise log for a well with a packer failure The techniques and/or conclusions are those of the authoring company and may not be shared by the other Prudhoe Bay Unit Working Interest Owners References I Smith, R C., and Steffensen R J., "Improved Interpretation Guidelines for Temperature Profiles in Water Injection Wells," SPE Paper 4649 Society of Petroleum Engineers Richardson Texas, 1973 Curtis, M R and Witterholt, E J., "Useofthe Temperature Log for Determining Flow Rates in Producing Wells," SPE Paper 4637, Society of Petroleum Engineers, Richardson, Texas,1973 McKinley, R M and Bower, F M "Noise Logging: Theory, Art of Interpretation, and Operational Procedures," July 1976 McKinley, R M., Bower, FM, Rumble, R.C.: "The Structure and Interpretation of Noise From Flow Behind Cemented Casing," Pet Tech P 329-338 March 1973 Norris, JD Tubing Leak De tector for Wells, and Method of Operating Same US Patent No 3,342.06 Hubbard Glen O Locating Holes in Tubing US Patent No 3,696,660 Huesser Juli e and Smith, David, ARCO Alaska, Inc Personal conversation Schlumberger software manual R M McKinley (Exxon Production and Research Company) has published much of the research on noise logging, much of which has been oriented toward its uses as a production logging tool and identifying channels behind casing He reports that single phase fluids produce higher noise levels in the 1000-2000 Hz range (4) Gas expanding into a water-filled channel produces increased noise in the 200-600 Hz range Typical noise logging equipment filters the signal into various frequency windows (Fig from Schlumberger (8» Field results to date have found increases in noise levels in all windows in the vicinity of the leak An example from a packer leak is provided (Fig 7) Noise logging is a slow process Discrete stops must be made, each requiring nearly one minute Noise attenuation in liquid is low, so stops can be widely spaced (10 - 500 feet) Attenuation in gas filled tubing, however, is high and stops should be made only two feet apart The noise tool is typically run on the same string as the temperature tool When in the noise data acquisition mode, no temperature or casing collar log data is available All possible extraneous surface noise should be eliminated when noise logging 51 Metric Conversion Factors bbl x 1589 873 ftx3.048 * ft x 2.831 685 psi x6.894757 OF (OF-32)/\.8 ·Conversion factor is exact E-OI = m3 E-OI=m E -02= m3 E+OO=kPa = °C SPEPF C M Michel is a Senior Production Engineer for BP Exploration (Alaska) He is currently involved in hydraulic fracturing He received a BS degree in chemical engineeri ng 1978 and MBA in 1982 both from Oregon State U., and worked as a process engineer in the pulp and paper industry between degrees He joined Sohio Petroleum (later BP Exploration) in 1982 and has assumed various production engineering assignments Michel is a registered petroleum engineer in Alaska Appendix-Noise Logging Noise logging can provide additional information on the location of the leak 128 SPE Production & Facilities, May 1995 ... 3-ldentification of tubing leak using the annular flow method Fig 4-ldentification of tubing leak using the annular injection method difference in the casing gas gradient and the flowing tubing gradient... tool and casing collar log A lift gas rate of over MMscflD, or enough to ensure a significant pressure drop across the leak, is preferred uncertainty remains Examples of tubing and packer leaks... value and the tubing pressure does not change, a packer leak is indicated If tubing pressure drops as annulus pressure increases, then the leak is somewhere in the tubing string If the leak is