NotesNov-09NOTES:The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetroThe papers relating to reservoir engineering have been catergorised for inclusion on the reservoirengineering.org.uk websiteThe affiiations searched were;Total No PapersReservoir Engineering RelatedBP551175Shell575279Chevron482238ConocoPhillips19168Marathon5537Total255129Schlumberger1130563Imperial College, London9553Heriot Watt University, Edinburgh235175(Anywhere in Article)Total35691717Total number of papers published post 2005 =10,00035% of papers published categorised

Well TestingOrganisationSourcePaper No.ChapterSectionSubjectTitleAuthorAbstractBPSPE90680Well TestingAnalysisDeconvolutionPractical Considerations for Pressure-Rate Deconvolution of Well-Test DataMichael M. Levitan, SPE, BP plc; Gary E. Crawford, SPE, WTS; and Andrew Hardwick, SPE, BP plcSummary Pressure-rate deconvolution provides equivalent representation of variable-rate well-test data in the form of characteristic constant rate drawdown system response.Deconvolution allows one to develop additional insights into pressure transient behavior and extract more information from well-test data than is possible by using conventional analysis methods.In some cases it is possible to interpret the same test data in terms of larger radius of investigation. There are a number of specific issues of which one has to be aware when using pressure-rate deconvolution.In this paper we identify and discuss these issues and provide practical considerations and recommendations on how to produce correct deconvolution results.We also demonstrate reliable use of deconvolution on a number of real test examples. Introduction Evaluation and assessment of pressure transient behavior in well-test data normally begins with examination of test data on different analysis plots [e.g. a Bourdet (1983 1989) derivative plot a superposition (semilog) plot or a Cartesian plot].Each of these plots provides a different view of the pressure transient behavior hidden in the test data by well-rate variation during a test.Integration of these several views into one consistent picture allows one to recognize understand and explain the main features of the test transient pressure behavior.Recently a new method of analyzing test data in the form of constant rate drawdown system response has emerged with development of robust pressure-rate deconvolution algorithm. (von Schroeter et al. 2001 2004; Levitan 2005). Deconvolved drawdown system response is another way of presenting well-test data. Pressure--rate deconvolution removes the effects of rate variation from the pressure data measured during a well-test sequence and reveals underlying characteristic system behavior that is controlled by reservoir and well properties and is not masked by the specific rate history during the test. In contrast to a Bourdet derivative plot or to a superposition plot which display the pressure behavior for a specific flow period of a test sequence deconvolved drawdown response is a representation of transient pressure behavior for a group of flow periods included in deconvolution. As a result deconvolved system response is defined on a longer time interval and reveals the features of transient behavior that otherwise would not be observed with conventional analysis approach. The deconvolution discussed in this paper is based on the algorithm first described by von Schroeter Hollaender and Gringarten (2001 2004). An independent evaluation of the von Schroeter et al. algorithm by Levitan (2005) confirmed that with some enhancements and safeguards it can be used successfully for analysis of real well-test data. There are several enhancements that distinguish our form of the deconvolution algorithm. The original von Schroeter algorithm reconstructs only the logarithm of log-derivative of the pressure response to constant rate production. Initial reservoir pressure is supposed to be determined in the deconvolution process along with the deconvolved drawdown system response. However inclusion of the initial pressure in the list of deconvolution parameters often causes the algorithm to fail. For this reason the authors do not recommend determination of initial pressure in the deconvolution process (von Schroeter et al. 2004). It becomes an input parameter and has to be evaluated through other means. Our form of deconvolution algorithm reconstructs the pressure response to constant rate production along with its log-derivative. Depending on the test sequence in some cases we can recover the initial reservoir pressure.SCHLUMBERGERSPE109860Well TestingAnalysis - Closed Chamber TestsA New Approach for Interpreting Pressure Data To Estimate Key Reservoir Parameters From Closed-Chamber TestsN.M.A. Rahman, SPE, Schlumberger, and M.S. Santo and L. Mattar, SPE, Fekete Assocs.Abstract A new technique for analyzing and modeling the pressure data from both flow and buildup periods in closed chamber tests (CCT) has been developed. It can be used for estimating the key reservoir parameters such as reservoir pressure permeability and skin. There are two aspects of the proposed approach - straight-line analysis and modeling. A novel approach is taken to develop the analytical solutions and procedures for both liquid and gas wells. Approximate solutions for the early-time and late-time pressure behavior are derived from the rigorous solution and are used for developing the basis for the straight-line analysis. A derivative function is utilized to ascertain if the data contains any portion of reservoir-dominated flow. Two synthetic data examples are presented to illustrate the process. Important contributions made in this study are as follows: The analysis procedure is simple enough to implement in a spreadsheet but is more accurate than the currently available methods. Calculating influx rates during the drawdown period is not an essential part of the analysis or modeling. Thus any noise in the data would not aggravate the accuracy of calculations. The complete analytical solution for modeling the entire CCT data will allow one to investigate possible test durations for CCTs and also to refine the parameters determined from approximate analyses. The presented technique is also applicable for analyzing drillstem test (DST) data as long as the flowing fluid does not reach the surface. Introduction Due to economics time constraints and environmental issues there has been increased interest in short-term tests for determining key parameters such as reservoir pressure permeability skin and fluid properties. Closed chamber tests (CCTs) are attractive due to their simplicity reliability and reduced impact on the environment. However the existing methods used for analyzing this kind of test data are based on the Horner method using the approximate rates during the flow period. As such the estimated reservoir parameters are susceptible to significant errors. This study presents a new systematic approach for interpretation of pressure data from CCTs based on the notion of a stepped change in wellbore storage. A schematic is presented in Fig. 1 to illustrate the process of CCTs. This is essentially equivalent to drillstem tests (DSTs) when the formation fluid does not get produced at the surface. The flow period is the one when the downhole valve X is open and the wellhead valve Y is closed. This flow period resembles a perforation inflow test. In contrast the buildup period is the one when the downhole valve X is closed and the wellhead valve Y is closed. The closing of the downhole valve reduces the effective wellbore storage and increases the chance of capturing the data dominated by the reservoir-dominated flow. A typical DST chart is presented in Fig. 2 highlighting the flow and buildup periods we are interested in. In this study Dt is the elapsed time since the beginning of inflow of fluid and Dtp is the duration of flow period. When Dt > Dtp it indicates a time within the shut-in period. The basis of the CCTs lies in the principles of slug tests originally designed for testing water wells. Ferris and Knowles1 were the early investigators who tried to extract transmissibility to water from late-time data captured from slug tests by using a straight-line technique. Much later Cooper et al.2 and Ramey et al.3 developed complete type-curve analysis techniques for estimating reservoir parameters from slug tests. Although significant groundwork for a complete straight-line analysis technique for the short tests was presented by Ramey and Agarwal4 this matter has not been pursued much since then. However Sageev5 presented some straight-line equations for analyzing aquifer data from slug tests. Few years ago Kuchuk4 introduced a technique for estimating reservoir pressure and permeability based on a straight-line method. With a view to analyzing perforation inflow/ outflow data Rahman et al.7-9 presented a complete methodology for extracting reservoir pressure permeability and skin.CHEVRONSPE110272Well TestingAnalysis - Fluivial ReservoirPTA/Seismic AttributeIntegrating Pressure Transient Test Data With Seismic Attribute Analysis to Characterize an Offshore Fluvial ReservoirAkshay Sahni, SPE, Ken Kelsch, SPE, Hathaiporn Samorn, and Chalatpon Boonmeelapprasert, SPE, ChevronAbstract Interpreting pressure transient tests in complex faulted and stratigraphic environments can be difficult. In fluvial depositional environments where sand continuity is a significant uncertainty pressure transient test interpretation can generate several non-unique solutions all of which may match test data. Using seismic attribute analysis to constrain pressure transient test interpretation leads to better understanding of reservoir heterogeneities and boundaries and is the central theme of this paper. Additionally seismic data can guide the design of pressure transient tests especially the test duration to evaluate key seismic anomalies. Other data such as production history core data formation evaluation from well logs analog information on channel geometry etc. is also important in getting a better understanding of reservoir description. While we briefly discuss all relevant data the focus of this paper is primarily on integrating seismic amplitude response with pressure transient test interpretation. The interpretation of the pressure transient test is done numerically guided by an initial interpretation of point bar and channel system geometry from seismic attribute analysis. The analysis of the build-up pressure derivative clearly shows the impact of point bar boundaries and connectivity across point bars. For the reservoir evaluated there was fluid and pressure communication across the point bars and this was reflected in the transient pressure analysis of the build-up and also from historical production data. The results presented in this paper illustrate the value of integrating geology geophysics and production data with well test interpretation for a fluvial reservoir. Introduction The integration of geology with well test interpretation has been discussed by Massaonnat and Bandiziol (1991) and subsequently by Corbett et al. (1998). The latter paper concludes that the integration of geoscience and well testing results in reduction of uncertainty in reservoir description especially in fluvial reservoirs. Zheng et al. (2003) illustrate this integration using geological petrophysical seismic attribute and well test data from a fluvial reservoir in the Gulf of Thailand. More recently Zheng (2006) concludes that numerical well test interpretation which incorporates reservoir geology and heterogeneity (rock and fluid) is the future of well testing. Raghavan et al. (2000) provide another example of a fluvial gas condensate reservoir where the integration of geologic and geophysical interpretations with measurements from flow tests helped in reservoir characterization. The authors discussed the advantages of using numerical interpretation of well tests as compared to classical analytical interpretation. They also noted that sub seismic features may be identified and their properties estimated by conducting flow tests. Rooij et al. (2002) studied point bar geometry connectivity and well test signatures in fluvial systems focusing on the lateral connectivity between point bars. Their work investigated the effect of different types of channel fill sequences on well test signatures and connectivity across channel fills. Toro-Rivera et al. (1994) summarized that flow characteristics of a fluvial reservoir can be better understood by the integrated interpretation of well test pressure data in a geologically coherent fashion.Heriot Watt UniversitySPE110272Well TestingAnalysis - Fluivial ReservoirPTA/Seismic AttributeIntegrating Pressure Transient Test Data With Seismic Attribute Analysis to Characterize an Offshore Fluvial ReservoirAkshay Sahni, SPE, Ken Kelsch, SPE, Hathaiporn Samorn, and Chalatpon Boonmeelapprasert, SPE, ChevronAbstract Interpreting pressure transient tests in complex faulted and stratigraphic environments can be difficult. In fluvial depositional environments where sand continuity is a significant uncertainty pressure transient test interpretation can generate several non-unique solutions all of which may match test data. Using seismic attribute analysis to constrain pressure transient test interpretation leads to better understanding of reservoir heterogeneities and boundaries and is the central theme of this paper. Additionally seismic data can guide the design of pressure transient tests especially the test duration to evaluate key seismic anomalies. Other data such as production history core data formation evaluation from well logs analog information on channel geometry etc. is also important in getting a better understanding of reservoir description. While we briefly discuss all relevant data the focus of this paper is primarily on integrating seismic amplitude response with pressure transient test interpretation. The interpretation of the pressure transient test is done numerically guided by an initial interpretation of point bar and channel system geometry from seismic attribute analysis. The analysis of the build-up pressure derivative clearly shows the impact of point bar boundaries and connectivity across point bars. For the reservoir evaluated there was fluid and pressure communication across the point bars and this was reflected in the transient pressure analysis of the build-up and also from historical production data. The results presented in this paper illustrate the value of integrating geology geophysics and production data with well test interpretation for a fluvial reservoir. Introduction The integration of geology with well test interpretation has been discussed by Massaonnat and Bandiziol (1991) and subsequently by Corbett et al. (1998). The latter paper concludes that the integration of geoscience and well testing results in reduction of uncertainty in reservoir description especially in fluvial reservoirs. Zheng et al. (2003) illustrate this integration using geological petrophysical seismic attribute and well test data from a fluvial reservoir in the Gulf of Thailand. More recently Zheng (2006) concludes that numerical well test interpretation which incorporates reservoir geology and heterogeneity (rock and fluid) is the future of well testing. Raghavan et al. (2000) provide another example of a fluvial gas condensate reservoir where the integration of geologic and geophysical interpretations with measurements from flow tests helped in reservoir characterization. The authors discussed the advantages of using numerical interpretation of well tests as compared to classical analytical interpretation. They also noted that sub seismic features may be identified and their properties estimated by conducting flow tests. Rooij et al. (2002) studied point bar geometry connectivity and well test signatures in fluvial systems focusing on the lateral connectivity between point bars. Their work investigated the effect of different types of channel fill sequences on well test signatures and connectivity across channel fills. Toro-Rivera et al. (1994) summarized that flow characteristics of a fluvial reservoir can be better understood by the integrated interpretation of well test pressure data in a geologically coherent fashion.SHELLSPE102304Well TestingAnalysis - Fractured Water InjectorPFOApplication of New Fall-Off Test Interpretation Methodology to Fractured Water Injection Wells Offshore SakhalinP.J. van den Hoek, SPE, Shell Intl. E&P B.V.; D. Volchkov, SPE, and G. Burgos, SPE, Sakhalin Energy; and R.A. Masfry, SPE, Shell Intl. E&P B.V.Abstract It is well established within the Industry that injection of (produced) water almost always takes place under fracturing conditions. Particularly when large volumes of very contaminated water are injected either for voidage replacement or disposal- large fractures may be induced over time. Unfortunately not much work has been carried out to date to provide methodologies for predicting and measurement of the size of waterflood-induced fractures. This contrasts to the vast amount of work that has been done for stimulation (e.g. propped) fractures. Injection Fall-Off (IFO) test analysis offers a cheap way to infer the dimensions of induced fractures from welltests. This paper presents a new methodology for IFO test analysis of fractured waterflood wells. This methodology derives the dimensions of induced fractures and the extent to which these are contained to the target injection layer. Furthermore the paper focuses on the application of this methodology to a waterflood offshore Sakhalin in the Russian far East. The methodology is based on an exact solution to the fully transient elliptical fluid flow equation around a closing fracture with changing conductivity face skin and multiple reservoir mobility zones. It also captures the case that during closure the fracture generally shrinks from adjacent geological layers. It is demonstrated that the analyses based on the storage and linear flow regimes can be integrated into one analysis in order to reduce error bounds. The method is applied to a number of examples in a waterflood offshore Sakhalin. Here start-up of injection wells was accompanied by regular IFO testing in order to monitor fracture growth over time. The interpreted fracture dimensions were compared with predicted dimensions using a recently developed in-house waterflood fracture simulator. The fracture lengths as interpreted from IFO test analysis appeared to be systematically lower than the predicted ones and a number of explanations for this difference are presented in the paper. 1. Introduction Injection Fall-Off (IFO) test analysis offers one of the cheapest ways to determine the dimensions of induced fractures. Unfortunately hardly any work has been carried out to date in order to provide a methodology for interpreting the pressure transient data of fractured water injection wells. This contrasts to the vast amount of work that has been carried out in the area of pressure transient analysis for wells with propped fractures. Both pressure transient tests during hydraulic fracture stimulation (called minifrac tests) (e.g.1) and pressure transient tests during production after stimulation (that is build-up tests) (e.g.2-5) have been studied extensively. The theories as developed in Refs.1-5 by now are well-accepted textbook methodologies. This paper deals with the subject of pressure fall-off analysis on fractured water injection wells. In this area the situation is entirely different from the one above in the sense that until recently 6-7 there existed no practical methodology dedicated to pressure fall-off analysis on fractured water injectors. The very limited interest in fall-off test analysis on fractured water injectors may be well related to the fact that most operators have been traditionally unaware that their water injectors are fractured. Only in recent years this situation has started to change. Unfortunately one of the consequences of the lack of a dedicated method of analysis is that fall-off tests on injectors are generally interpreted in the wrong way even if one realises that they are fractured. Typically such interpretations lead to wellbore storage coefficients that can be up to orders of magnitude too high and to fracture lengths only based on analysis of the linear formation flow period (e.g.8). The objective of our study is to fill the gap as described above i.e. to provide a dedicated interpretation methodology for fall-off tests on fractured water injectors and illustrate the use of this on a specific set of field examples. In the current paper we focus on the application of this method to fractured injection wells in a waterflood offshore Sakhalin Island in the Russian far East. In this field start-up of injection wells was accompanied by regular IFO testing in order to monitor the induced fracture growth over time. This is of importance both from the point of view of well injectivity and of induced fracture containment to the appropriate injection zone.SHELLSPE98098Well TestingAnalysis - Fractured WellSRTNew Analysis of Step-Rate Injection Tests for Improved Fracture Stimulation DesignK. Lizak, Shell; K. Bartko, Saudi Aramco; F. Self, G. Izquierdo, and M. Al-Mumen, HalliburtonAbstract Prehydraulic fracture diagnostic pumping analysis has recently improved with the use of new analysis techniques such as G-Function derivative plots after-closure analysis and step-rate tests. This paper analyzes various types and combinations of step-rate injection tests from many different formations around the world to determine the usefulness of these tests. The analysis uses wells with both surface and bottomhole gauge data and in some instances compares the results of the two. The final results of the stimulation treatments are also compared to the prefrac analysis. While the results of these tests provide information on the presence of excess near-wellbore friction or tortuosity what is often not taken into account is that this tortuosity often destroys the usefulness of these step-rate tests in providing much sought-after data such as accurate fluid efficiency and closure pressure numbers. The focus of this paper will be on step-up and step-down analysis with the result being a new type of graph that provides an indepth look at the quality of these tests in any given well. Often these tests are performed and erroneously analyzed because of the effects of tortuosity with the end result being either the data is ignored or discarded. Techniques are provided for analyzing these tests and suggestions are given to improve the results obtained from these tests. Introduction Oil and gas wells of different permeabilities and lithologies often need to be effectively fracture stimulated to provide operators with sufficient economic return on investment. In an effort to ensure that a stimulation treatment can be placed injection tests or fracture stimulations without proppant or with minimal amounts of proppant have been employed to test a formations capacity to receive a treatment and to help optimize the final treatment design. The design of these injection tests usually called minifracs or datafracs is based on the type of information the operator or stimulation designer seeks. Information that can be obtained or inferred from these tests include closure stress or minimum stress bounding stresses fracture geometry presence of natural fractures permeability leakoff coefficient fluid efficiency pore pressure fracture gradient fracture extension pressure net pressure and excess friction.[1-3] Variations that can be made in these tests include injection rate fluid type fluid loss additives proppant type proppant volumes and concentrations and finally combinations of various diagnostic injections. The order in which these tests are performed can also have an influence on the outcome of the analysis and final treatment design. One such test is the step-up step-rate test. In this test injection into a formation is begun at a slow rate for a fixed amount of time and the rate is then increased and again held for the same amount of time. This is repeated in an attempt to achieve three matrix injection rates and three fracture injection rates. A graph of rate vs. bottomhole pressure is then made at the stabilized points and fracture-extension pressure is indicated as the point where the pressure breaks over or large increases in rate provide small increases in bottomhole treating pressure. As will be discussed a plot of bottomhole pressure vs. injection rate provides a myriad of useful information provided there is good communication between the wellbore and the formation. It will also be shown that the presence of tortuosity virtually destroys this test and while it has been proposed that near-wellbore friction can be mathematically removed from this test the supplied analysis demonstrates that this is rarely the case. Another rate-dependent test is the step-down step-rate test. It has been proposed and is now generally accepted that this test can provide a rate dependent friction value for tortuosity and perforation friction and can differentiate between the two. The main requirements of this test are that it be sufficiently rapid or sufficiently slow in the case of formations with very low leakoff so that the fracture geometry does not change during the step-down test and that a displacement fluid with known friction values or bottomhole pressure is accurately determined from a live annulus or bottomhole gauges.OnePetroOnePetroCHEVRONSPE105134Well TestingAnalysis - Horizontal WellsCarbonate ReservoirChallenges Encountered During a Comprehensive Test Analysis for a Horizontal Well in a Thin, Carbonate Reservoir of the Greater Burgan Field, KuwaitA.K. Ambastha, SPE, and M. Anderson, SPE, Chevron Corp.; H. Gandhi, SPE, Kuwait Oil Co.; and P.-D. Maizeret, SPE, SchlumbergerAbstract Mauddud reservoir in the Greater Burgan field is a thin carbonate reservoir containing light oil in a 10-20 ft target zone with good porosity. Matrix permeability is low and natural fracture density can be variable in this reservoir. Thus this reservoir must be exploited using horizontal wells. Recently a 2 270 ft long horizontal well has been drilled in an area interpreted to have high fracture density. A comprehensive test program including flowing and static pressure surveys modified isochronal test two buildup tests and FloScan Imager (FSI) log has been carried out to evaluate this well. The material discussed in this paper provides a good basis for evaluating long-term production potential of horizontal wells exploiting tight and thin reservoirs with reservoir pressures close to the bubble-point pressure. Test data interpretation highlights successful development of inflow and tubing performance relationships bubble-point pressure estimation as well as quantification of reservoir parameters. This paper describes unique challenges encountered in interpreting transient pressure data from this horizontal well due to multi-phase flow and short production time. Impact of derivative shape on model selection is also discussed. The effects of analysis methodologies based on specific flow regimes vs. total model fitting single- vs. multi-phase production treatment and assumptions regarding effective well length on the computed values of reservoir parameters emphasize the attention required to obtain meaningful interpretation from horizontal well tests. FSI data was instrumental in interpreting effective length of the well. Overall this test program yielded information that was critical in managing sustained production from this well characterizing the effects of the natural fractures on production behavior as well as quantifying reserves for this tight reservoir. Introduction The Mauddud reservoir is a thin underdeveloped low permeability carbonate reservoir unit within the Greater Burgan field. The matrix permeability is low and consequently the few vertical wells completed in the 10-20 ft target zone exhibit low or no productivity. In the 1990s 16 horizontal wells were drilled whose production performance is discussed in Ref. 1. In 2005 three horizontal wells including one tri-lateral as discussed in Ref. 2 have been drilled to further exploit this tight reservoir. This paper discusses challenges encountered during testing and analysis of the first horizontal well drilled in the 2005 program. The first Mauddud horizontal well of the 2005 program is a 2 270 ft long horizontal well targeting an area interpreted to have high fracture density (see well schematic in Figure 1). The main purpose of the well is to understand the contribution of the fractures and determine to which extent they enhance the well productivity. A pressure transient test program was carried out to establish the potential of the well and shed light on the reservoir structure. Different phases of the test program can be summarized as (see Figures 2 and 3). Initial clean-up on full choke followed by a shut-in period to let the reservoir return to its initial pressure Initial 8-hour flow period on 24/64 choke to perform flowing surveys and attempt to take a bottom hole sample followed by a 2.5-day initial build-up to get a first estimate of the reservoir pressure and key parameters Modified isochronal test: Three 8-hour flowing and shut-in periods followed by a 6-day extended flow period and a 14-day build-up Pressure Traverse To compute gradients from the pressure and temperature surveys it is necessary to convert the measured depth to true vertical depth. For this well the deviation at the bottom most point of the survey is around 60. The well trajectory can be seen in Figure 4. The pressure and temperature traverses are plotted on Figures 5 and 6 respectively.SCHLUMBERGERSPE105134Well TestingAnalysis - Horizontal WellsCarbonate ReservoirChallenges Encountered During a Comprehensive Test Analysis for a Horizontal Well in a Thin, Carbonate Reservoir of the Greater Burgan Field, KuwaitA.K. Ambastha, SPE, and M. Anderson, SPE, Chevron Corp.; H. Gandhi, SPE, Kuwait Oil Co.; and P.-D. Maizeret, SPE, SchlumbergerAbstract Mauddud reservoir in the Greater Burgan field is a thin carbonate reservoir containing light oil in a 10-20 ft target zone with good porosity. Matrix permeability is low and natural fracture density can be variable in this reservoir. Thus this reservoir must be exploited using horizontal wells. Recently a 2 270 ft long horizontal well has been drilled in an area interpreted to have high fracture density. A comprehensive test program including flowing and static pressure surveys modified isochronal test two buildup tests and FloScan Imager (FSI) log has been carried out to evaluate this well. The material discussed in this paper provides a good basis for evaluating long-term production potential of horizontal wells exploiting tight and thin reservoirs with reservoir pressures close to the bubble-point pressure. Test data interpretation highlights successful development of inflow and tubing performance relationships bubble-point pressure estimation as well as quantification of reservoir parameters. This paper describes unique challenges encountered in interpreting transient pressure data from this horizontal well due to multi-phase flow and short production time. Impact of derivative shape on model selection is also discussed. The effects of analysis methodologies based on specific flow regimes vs. total model fitting single- vs. multi-phase production treatment and assumptions regarding effective well length on the computed values of reservoir parameters emphasize the attention required to obtain meaningful interpretation from horizontal well tests. FSI data was instrumental in interpreting effective length of the well. Overall this test program yielded information that was critical in managing sustained production from this well characterizing the effects of the natural fractures on production behavior as well as quantifying reserves for this tight reservoir. Introduction The Mauddud reservoir is a thin underdeveloped low permeability carbonate reservoir unit within the Greater Burgan field. The matrix permeability is low and consequently the few vertical wells completed in the 10-20 ft target zone exhibit low or no productivity. In the 1990s 16 horizontal wells were drilled whose production performance is discussed in Ref. 1. In 2005 three horizontal wells including one tri-lateral as discussed in Ref. 2 have been drilled to further exploit this tight reservoir. This paper discusses challenges encountered during testing and analysis of the first horizontal well drilled in the 2005 program. The first Mauddud horizontal well of the 2005 program is a 2 270 ft long horizontal well targeting an area interpreted to have high fracture density (see well schematic in Figure 1). The main purpose of the well is to understand the contribution of the fractures and determine to which extent they enhance the well productivity. A pressure transient test program was carried out to establish the potential of the well and shed light on the reservoir structure. Different phases of the test program can be summarized as (see Figures 2 and 3). Initial clean-up on full choke followed by a shut-in period to let the reservoir return to its initial pressure Initial 8-hour flow period on 24/64 choke to perform flowing surveys and attempt to take a bottom hole sample followed by a 2.5-day initial build-up to get a first estimate of the reservoir pressure and key parameters Modified isochronal test: Three 8-hour flowing and shut-in periods followed by a 6-day extended flow period and a 14-day build-up Pressure Traverse To compute gradients from the pressure and temperature surveys it is necessary to convert the measured depth to true vertical depth. For this well the deviation at the bottom most point of the survey is around 60. The well trajectory can be seen in Figure 4. The pressure and temperature traverses are plotted on Figures 5 and 6 respectively.SHELLSPE104480Well TestingAnalysis - Horizontal WellsPTAHorizontal Well" Pressure Transient Analysis for Gulf of Mexico Reservoirs (Adapting the Slant Well Solution to Layered Media)"P.S. Fair, Shell International Exploration and Production Inc.Introduction There are three objectives of this paper. The first objective is to present a generalized geometric skin for deviated wells for all angles up to 89.9 extending Cincos slant well solution to smaller bed sizes where the line source approximation is not a valid assumption. The second objective of this paper is to extend the slant well solution to layered reservoirs without reservoir crossflow i.e. no significant vertical permeability between individual layers within the reservoir. The third objective of this paper is to present a methodology for the analysis of high angle well pressure transient tests. This paper compares the high angle and horizontal well solutions showing Cincos slant well solution is valid provided the bed is sufficiently thick. As a practical matter the standard horizontal well is rare. Most of the horizontal wells drilled in the Gulf of Mexico (GoM) are better approximated by the deviated well model because they transect all beds within the reservoir to ensure complete drainage of the reservoir. Since shales dividing the reservoir into multiple vertical compartments provide the impetus for drilling a high angle transect instead of a horizontal well penetrating a single compartment this paper provides insight into the impact of shales dividing the reservoir into non-communicating layers. The presence of even two shales dividing a reservoir into three noncommunicating layers can decrease the expected productivity of a high angle well by as much as 50%. Next a methodology for interpreting high angle well tests is introduced that attempts to address the problems of non-uniqueness associated with well angle and average bed thickness. Finally several example analyses are provided illustrating pressure analysis of high angle wells. These examples support the applicability of this high angle pressure analysis technique through the early arrival of the late time reservoir pseudo-radial flow found in the well tests. In addition an example well exhibiting a loss of layers (i.e. reservoir permeability thickness (kh)) with production and the restoration of reservoir kh with remedial stimulation substantiates this work.BPSPE100836Well TestingAnalysis - Low PermeabilityRate Dependent Transient FlowAnalysis of Rate Dependence in Transient Linear Flow in Tight Gas WellsM. Ibrahim, Suez Canal U., and R.A. Wattenbarger, Texas A&M U.Abstract Many tight gas wells (permeability less than 0.1 md) exhibit linear flow through their transient period. This transient period may last for years in some cases. It has been learned that this behavior differs in many ways from radial flow behavior. This paper reports another import difference between linear flow and radial flow rate sensitivity. It has been shown and accepted for years that real gas pseudo-pressure can be used to apply analytical solutions to transient radial flow. However it has been noticed that analytical solutions can be in serious error when applied to transient linear flow. Specifically the slope of the departs from the analytical value as the flow rates or degree of drawdown become higher. This paper demonstrates the rate/drawdown sensitivity of transient linear flow. Then a correction factor is presented which corrects the slope of the plot and improves the accuracy of and OGIP as calculated from production/pressure performance. Introduction Many wells in tight gas reservoirs have long-term performance which exhibit only linear flow not radial flow during the transient period. Wells have been observed which stay in the transient linear flow regime for several years. Some of these wells have hydraulic fractures and some do not. It is usually not practical to analyze tight gas wells with build-up tests but long term production and pressure data can be used for analysis. Previous papers have presented methods of analysis1-5. The analysis of these wells comes from plotting vs. and observing the slope and the end of the straight line tesr (end of the transient linear flow period). From these values and OGIP can be calculated. The equations for this analysis are given in Table 1. The value of permeability can be calculated if the value of Ac can be estimated. For example Ac can be estimated for a hydraulic fracture of known fracture length. However in some tight gas wells there is no hydraulic fracture and linear flow probably occurs because of a natural fracture system. The value of can be thought of as a flow capacity for these wells. The drawdown/rate dependency of this analysis is quite different than analysis of radial flow. This difference was demonstrated with reservoir simulation. Then a correction method was developed to improve the accuracy of analysis of transient linear flow. Solutions for Radial Flow It has long been accepted that radial flow transient solutions can be approximated by analytical solutions in terms of m(p) regardless of flow rate. Constant rate solutions have been emphasized but it can also be shown that constant pwf flow can also be approximated by analytical solutions regardless of the level of drawdown. Figs. 1 and 2 demonstrate this point. These figures show the results of simulated transient radial flow for a wide variety of rate and drawdown values. Specifically note that all the semi-log straight line slopes are parallel to the analytical solutions in Figs. 1 and 2. This means that when permeability is calculated from the semi-log straight line slope it will tend to be accurate. However it was found that this is not true for linear flow. Effect of Drawdown on Transient Linear Flow (Constant pwf) A plot of vs. gives a straight line with slope for the analytical solution. The slope of this plot can be used to calculate the value of . The equation for this is shown in Table 1.SCHLUMBERGERSPE110576Well TestingAnalysis - Multi-Fractured WellsStacked ReservoirsA Unique Methodology for Evaluation of Multi-Fractured Wells in Stacked-Pay Reservoirs Using Commingled Production and Rate Transient AnalysisJ.F. Manrique, Occidental Oil and Gas Corporation, and B.D. Poe Jr., SchlumbergerAbstract We present a unique methodology designed for evaluation and optimization of multi-fractured wells in stacked pay reservoirs using commingled production. The specialized diagnostic procedures are based on rate-transient analyses and uses historical production data (rates and cumulative) and the results from production logs to; 1) determine the flow rates for each individual stage in a multi-fractured well 2) apply rate-transient solutions that use rate-normalized-pressures and superposition-in-time to evaluate response accordingly to the fracture flow periods 3) estimate reservoir and fracture effective properties and 4) evaluate the completion efficiency. The field examples presented in the paper demonstrates the application of the production optimization methodology in practice. The approach permits quantification of the reservoir and fracture properties on a layer-by-layer or frac stage-by-stage by evaluating the production well history as an extended drawdown and in combination with direct physical measurements of the flow rates and flowing pressures. Such a unique procedure provides a great advantage since parameters such as; permeability (keffective) fracture length (Xf effective) conductivity (kfbf)effective and dimensionless conductivity (CfD or FCD) can now be obtained for each individual fracture stage. In addition to the effective properties the methodology allows for estimation of the drainage area and skin for unfractured zones and fracture half-length and conductivity for the hydraulically fractured reservoir layers. The methodology is applicable to all types of reservoirs however most of our field experience has taken place in the evaluation and optimization of stacked-pay tight permeability reservoirs and low conductivity fractures where other forms of conventional reservoir characterization techniques are technically difficult and/or cost-prohibitive. The optimization methodology allows evaluation of the fracture performance efficiency in terms of the reservoir response and contribution identification of non-fractured zones bypassed zones (zones without a frac) under-designed fractures low conductivity values (and steps for improving it) re-fracturing candidates and identification of remaining well potential deliverability. Introduction Optimization of the productivity of an oil or gas well is a process of evaluating all of the available practical completion and operating condition scenarios that can be applied to a well to achieve maximum productivity. The objective is to significantly increase the productivity of the well to maximize the financial performance of multi-fractured wells. From a performance perspective the optimum production and completion would be the one that results in the maximum economic benefit to the operator. In practice the optimum completion design and operating condition well/reservoir production option used will commonly be the optimum solution indicated on an economic basis or at least a reasonable melding of the optimum economic and technical options considered. An innovative robust and unique production optimization methodology is reported in the paper that permits the quantification of the well and reservoir in situ properties on a layer-by-layer zone-by-zone or frac stage-by-stage basis by evaluating the drawdown production performance of the well in combination with direct physical measurements of layered reservoir flow rates and wellbore flowing pressures. Methodology The completion and production optimization methodology reported here relies on determination of the completion efficiency in terms of the evaluation of the in-situ reservoir and well properties from multilayer reservoirs. This is achieved by (1) Characterization of hydraulic fractures individual or within a multi-fractured system (equivalent fracture) by means of the dimensionless fracture conductivity dimensionless stimulation index and dimensionless productivity solution (2) Analysis of the allocated flow rate contribution from each individual completion by using specialized quantitative rate transient diagnostics and analyses based on the distinctive behavior of transient fracture flow.BPSPE104581Well TestingAnalysis - MultilateralsTransient Behavior of Multilateral Wells in Numerical Models: A Hybrid Analytical-Numerical ApproachC. Aguilar, SPE, BP Alaska, and E. Ozkan, SPE, H. Kazemi, SPE, M. Al-Kobaisi, SPE, and B. Ramirez, SPE, Colorado School of MinesAbstract This paper presents an extension of transient well index approach to simulate pressure transient behavior of multilateral wells. This approach uses an analytical solution for the well index at early times and switches to the numerical well index at late times. The use of the transient well index eliminates the need for excessive grid refinement around the well. In this paper we have improved the accuracy of the transient well index approach and have provided for a flexible and easily implementable approach to place multilaterals in conventional Cartesian-grid reservoir models. Introduction Pressure-transient responses of wells are conventionally analyzed and interpreted by using analytical solutions of diffusion equation for relatively simpler reservoir architectures. For more complex reservoir situations involving multi-phase flow and reservoir heterogeneity numerical simulation is usually the only resort. Numerical simulators generally focus on the long-term performance of reservoirs. These simulators are not very sensitive to the short-term characteristics of flow in the near-wellbore region which is the focus of the short-term pressure-transient tests. For example the conventional transmissibility and well indices used in numerical simulation may adequately represent fluid movement between relatively large grid blocks as well as the fluid withdrawal or injection at well blocks over relatively large time steps when the transient radius of investigation of the well is sufficiently large. Furthermore these simulators fail to account for the flow convergence near the well accurately at shorter times unless very small grid and time steps are used. Grid refinement around well has been used both to improve numerical calculation of bottom-hole pressure during transient period and flow convergence. However a cursory grid refinement may not produce the desired accuracy; thus increasing the need for very fine grid that requires more computational power and time. In addition special grid structures are often required to capture the details of flow convergence around complex wellbores and to simulate the associated transient flow regimes add to the overall complexity of the numerical computation. Objective The objective of this paper is to improve the representation of single- and dual-lateral wells in numerical models for more accurate and computationally efficient simulation of pressure-transient responses. Also a practical approach will be presented to model the dual-lateral wells in uniformly distributed Cartesian grid. This approach involves proper accounting for the orientation length and friction-head loss of the multi-lateral segment crossing a grid block. The proposed approach can be easily implemented in the conventional reservoir simulators without compromising the computation time. Outline After a summary of the pertinent literature and background we first present the improvement of well transmissibility for a single lateral. Then we discuss the addition of a second lateral to the model. We finally compare the accuracy of the numerical model against analytical solutions under various conditions of heterogeneity and skin effect. Literature Review Blanc et al. (1999) applied an unsteady-state radial flow equation for vertical wells known as transient well index to simulate pressure transients more accurately. They defined a well-block radius that varied with time and was different from the steady- and unsteady-state definitions of the well-block radius proposed in the earlier studies by Peaceman (1977 1983) and Babu et al. (1991). This approach eliminated the need for excessive grid refinement around the well.SCHLUMBERGERSPE116969Well TestingAnalysis - Multilayer ReservoirLayer PropertiesIdentifying Layer Permeabilities and Skin Using a Multi-Layer Transient Testing Approach in a Complex Reservoir EnvironmentMoustafa Eissa, Sameer Joshi, and Kamaljeet Singh, SPE, Schlumberger, and Ajay Bahuguna and Mohamed Elbadri, GNPOCAbstract Conventional pressure transient testing using a pressure gauge positioned at a fixed depth in a well has historically been the main source of permeability and skin estimation in formations. However if a well is completed as a multi-layer commingled producer then this conventional approach makes it difficult to measure the permeability and skin of individual layers. Greater Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan has several wells that commingle production from the Aradabia Bentiu-2 and Bentiu-3 formations. These formations are highly variable in terms of the reservoir properties oil types and pressure regimes. A selective inflow performance (SIP) test was carried out during production logging (PL) jobs in some of these wells and it indicated that the productivity index (P.I.) of the individual layers varies widely ranging from 1.5 to 15 b/d/psi. This illustrated the need for a method to estimate the permeability and skin of each layer. This information was needed for reservoir model calibration well productivity prediction low productivity diagnosis and remedial action selection. Two solutions were proposed to GNPOC; use the conventional technique of isolating each layer and testing it separately or carry out a commingled multi-layer transient (MLT) test with a PL tool. In an MLT test in addition to the normal PL runs individual pressure transient stations are also recorded at the top of each contributing layer. The MLT test measures the flow rate and wellbore pressure above each producing layer for different surface flow rates during the infinite-acting phase. These individual layer flow rates and pressure transients are used to calculate the individual layer properties. GNPOC decided to go in for the MLT testing option and two wells were analyzed. In the first well MLT testing showed that one of the layers had a very high permeability compared to the other layers. It depleted much faster and had early water breakthrough. Consequently a water shut-off job is planned for this layer. In the second well MLT analysis showed that the upper layer had poorer permeability as compared to the lower layers. However this layer holds good oil reserves. Hence this well is a good candidate for future side tracking into the upper layer in order to exploit the untapped reserves in this layer. In this paper we will discuss the MLT testing technique introduce a workflow for the analysis and then will discuss the results of the analyses for two examples from GNPOC. Based on the success of these cases multi-layer transient testing is estabilished as a preferred testing technique in this complex reservoir environment.CHEVRONSPE113903Well TestingAnalysis - Multiphase2 PhaseUse of Transient Testing Data To Calculate Absolute Permeability and Average Fluid SaturationsMedhat M. Kamal and Yan Pan, Chevron Energy Technology CompanyAbstract A new well testing analysis method is presented. The method allows for calculating the absolute permeability of the formation in the area influenced by the test and the average saturations in this area. The method applies to two-phase flow in the reservoir (oil and water or oil and gas). Future expansion to three-phase flow is possible. Current analysis methods yield only the effective permeability for the dominant flowing phase and the total mobility of all phases. The new method uses the surface flow rates and fluid properties of the flowing phases and the same relative permeability relations used in characterizing the reservoir and predicting its future performance. The method has been verified by comparing the results from analyzing several synthetic tests that were produced by a numerical simulator with the input values. Use of the method with field data is also described. The new method could be applied wherever values of absolute permeability or fluids saturations are used in predicting well and reservoir performance. Probably the major impact would be in reservoir simulation studies where the need to transform well testing permeability to simulator input values is eliminated and an additional parameter (fluids saturations) becomes available to help history match the reservoir performance. This work will also help in predicting well flow rates and where absolute permeability changes with time (e.g. from compaction). Results showed that the values of absolute permeability in water-oil cases could be reproduced within 3% of the correct values and within 5% of the correct values in gas-oil cases. Errors in calculating the fluid saturations were even less. One of the main advantages of this method is that the relative permeability curves used in calculating the results and later on in using the results are the same ensuring consistent process. The impact of this study will be to expand the use of the information already contained in transient data and surface flow rates of all phases. The results will provide engineers with additional parameters to improve and speed up the prediction of well and reservoir performances in just about all studies. Background Information Design and analysis of transient well testing was initially developed for single phase flow in the reservoir. Most of the well testing work done today assumes that a dominant phase flows in the reservoir and uses the equations developed for single phase flow to calculate well and reservoir properties. It is reasoned that using the single-phase flow equations while working with actual field data one ends up obtaining the effective permeability of the specific phase whose flow rate and fluid properties are used in the analysis (Earlougher 1977 p.18). Another approach is to use the Perrine method (Perrine 1956; Martin 1959; Miller et al. 1967) where a total flow mobility is calculated as shown in equation1 Equation (1) Several studies addressed transient testing under specific multiphase flow conditions. Examples include work on solution-gas-drive reservoirs (Raghavan 1976) gas condensate reservoirs (Jones and Raghavan 1988) water flooding reservoirs (Abbaszadeh and Kamal 1989) and coal-bed-methane reservoirs (Kamal and Six 1991). Results from the previously mentioned studies have been helpful in providing answers to production and reservoir engineering applications like wellbore conditions productivity indices and average reservoir pressures.SCHLUMBERGERSPE104059Well TestingAnalysis - Naturally Fractured ReservoirPartial PenetrationPressure Transient Analysis of Partially Penetrating Wells in a Naturally Fractured ReservoirK. Slimani, Sonatrach; D. Tiab, U. of Oklahoma; and K. Moncada, SchlumbergerAbstract Often and for many reasons the wellbore does not completely penetrate the entire formation yielding a unique early-time pressure behavior. Some of the main reasons for partial penetration in both fractured and unfractured formations are to prevent or delay the intrusion of unwanted fluids into the wellbore i.e. water coning. A similar early-time pressure behavior may be due to the presence of plugged perforations. Drilling problems associated with high mud losses when the well encounters fractures often prevent well penetration of the total formation thickness. Penetration in naturally fractured reservoirs is usually minimal (10 to 20%) but with the right mud it can reach 50% and in some cases 100%. Such well completions are referred to as limited-entry restricted-entry or partially penetrating wells. The transient flow behavior in these types of completions is different and more complex compared to that of a fully penetrating well. This paper proposes a method for identifying on the pressure and pressure derivative curves the unique characteristics of the different flow regimes resulting from these types of completions and to obtain various reservoir parameters such as vertical and horizontal permeability fracture properties and various skin factors. Both naturally fractured and unfractured (homogeneous) reservoirs have been investigated. For unfractured and homogeneous formations a spherical or hemispherical flow regime occurs prior to the radial flow regime whenever the penetration ratio is twenty percent or less. A half-slope line on the pressure derivative is the unique characteristic identifying the presence of the spherical flow. This straight line can be used to calculate spherical permeability and spherical skin values. These parameters are then used to estimate vertical permeability anisotropy index and skin. For a naturally fractured formation the type curves of the pressure and pressure derivative reveal that the combination of partial penetration and dual-porosity effects yields unique finger prints at early and transition periods. These unique characteristics are used to calculate several reservoir parameters including the storage capacity ratio interporosity flow coefficient permeability and pseudo-skin. Equations have been developed for calculating the skin for three partial completion cases: top center and bottom. The analytical solution was obtained by combining the partially penetrating well model in a homogeneous reservoir with the pseudo-steady model for a naturally fractured reservoir. The interpretation of pressure tests in both systems i.e. fractured and unfractured reservoirs is performed using Tiabs Direct Synthesis (TDS) technique for analyzing log-log pressure and pressure derivative plots. TDS uses analytical equations to determine reservoir and well characteristics without using type-curve matching. These characteristics are obtained from unique fingerprints such as flow regime lines and points of intersection of these lines that are found on the log-log plot of pressure and pressure derivative. It isapplied to both drawdown and buildup tests. Several numerical examples are included to illustrate the step-by-step application of the proposed technique. Introduction Over the last four decades naturally fractured reservoirs have been a topic of continuous research due to the fact that many producing fields of the world are found in such type of formations. These reservoirs differ in geological and petrophysical properties from homogeneous reservoirs. Additionally in many oil and gas reservoirs the producing wells are completed as partially penetrating wells; that is only a portion of the pay zone is perforated. This may be done for a variety of reasons but the most common one is to prevent or delay the intrusion of unwanted fluids into the wellbore. Generally pressure behavior of a partially penetrating vertical well in naturally fractured reservoirs has been considered and interpreted as fully penetrating isotropic fracture permeability with the existing of only the mechanical skin. But in the reality the partial penetration effect causes a characteristic shape on the pressure derivative curves (which allowsestimation of some reservoir parameters) at early and transition time and differ from that of fully penetrating. Furthermore it causes an additional pressure drop near the wellbore that is known as the pseudo-skin.SCHLUMBERGERSPE120515Well TestingAnalysis - Radius of InvestigationReserve EstimationRadius of Investigation for Reserve Estimation From Pressure Transient Well TestsFikri J. Kuchuk, SPE, SchlumbergerAbstract Although it is often used in pressure transient testing radius of investigation still is an ambiguous concept and there is no standard definition in the petroleum literature. The pressure diffusion corresponds to an instantaneous propagation of the pressure signal in the entire spatial domain when a flow rate or pressure pulse is applied to the sandface (beginning of a drawdown or injection) of a well. However the initial pressure propagation is not diffusive but it propagates like a wave with a finite speed. If we have a pressure gauge at a distance we will only start to detect a pressure change (drop or increase) after a few seconds or minutes even if we have a perfect pressure gauge with 0.0 psi resolution. After the initial propagation pressure starts to diffuse or propagates as diffusion and we start to observe pressure change at a given space and time above the pressure gauge resolution and natural background noise which could be as high as 0.1 psi. One of the constant background noises is the effect of tidal forces. In this work we present new formulae for radius of investigation in radial-cylindrical reservoirs and new techniques for general systems. The new formulation takes into account the production rate from the system formation thickness and gauge resolution. It is shown that the conventional radius of investigation formula (Earlougher 1977) for radial-cylindrical systems which is given as (Equation) yields very conservative estimates and it could be as high as 30 to 50% lower. Radius of investigation if fundamental for understating of the tested volume; i.e. how much reservoir volume is investigated for a given duration of a transient test? For exploration wells the reservoir volume investigated is one of the main objectives of running drillstem test (DST) or production tests.Therefore how far pressure may diffuse (radius of investigation) during a transient test is very important for exploration well testing. Introduction The challenge in estimating reserves from pressure transient well test data very often arises in oil and gas explorations as well as in other oil industry applications. Thus determining radius of investigation during a pressure transient test becomes critically important. It may also be called transient drainage radius. Although it is often used in pressure transient testing radius of investigation still is an ambiguous concept and there is no standard definition in the petroleum literature. For instance it is defined at http://www.glossary.oilfield.slb.com/ as the calculated maximum radius in a formation in which pressure has been affected during the flow period of a transient well test. This definition is not completely accurate when we apply an instantaneous source during which pressure may diffuse to a long distance. Therefore to understand the radius of investigation first we look at the pressure distributions in a 1D radial-cylindrical homogeneous reservoir produced by a fully completed vertical well in which after the wellbore storage effect the flow regime is predominantly radial before the effect of any outer boundary. Note that this may not be true for wells in nonhomogeneous and heterogeneous formations and reservoirs. Nevertheless understanding the fundamental radial flow regime is essential to interpreting pressure transient testing and its radius of investigation; i.e. how much reservoir volume if investigated for a given duration of a transient test? For exploration wells the reservoir volume investigated is one of the main objectives of running DST or production tests. Therefore how far pressure may diffuse (radius of investigation) during a transient test is very important for exploration well testing where very important decisions are made based on total volume are seen by DST or other production tests.SCHLUMBERGERSPE123115Well TestingAnalysis - Real Time EvaluationReal-Time Evaluation of Pressure Transients: Advances in Dynamic Reservoir MonitoringC. Contreras, SPE, S. Bodwadkar, SPE, and A. Kosmala, SPE, SchlumbergerAbstract Reservoir engineers operating in mature fields across the world struggle to get necessary reservoir data to make their exploitation plans more realistic. Pressure transients are the most effective way to understand the dynamic behavior of the reservoir. Loss of production and cost of acquiring data versus the benefits has always been a classical management dilemma. With the advent of digital oilfield technology the pressure and hence the deterioration in well deliverability can be continuously and cost effectively monitored. This paper illustrates how real-time data can be used to make decisions on when to invest in pressure transient tests and when a test is run how to minimize the downtime. The case studies presented here are for wells on electrical submersible pumps in various types of reservoirs across Latin America. The paper briefly discusses the three pillars of digital oilfield; technology processes and people and how they work together to achieve continuous reservoir and production optimization. Reservoir analysis for wells on electrical submersible pumps (ESP) is challenging due to the restrictions imposed by the downhole equipment. Our work presented here focuses on developing workflows and interpretation techniques for this unique environment. Having sensors downhole provides operators with an opportunity to get pressure drawdown and buildup data when the ESP starts and stops. For the wells we monitor 10% of these unscheduled events provided much coveted reservoir information without having to stop the production intentionally. For the scheduled pressure transient events the data acquisition rates were actively changed to ensure sufficient high quality data. Also the length of the test was decided in real time to make sure that the test was long enough to meet the objectives but not too long to increase the cost without additional benefits. Thus with real-time technology we were able to overcome the shortcomings of traditional well testing and address the concerns of both engineers and the management. Case studies are presented where production enhancement opportunities were uncovered as a result of scheduled and unscheduled events on wells producing with ESPs. The results show that more than 70% of wells can benefit from stimulation potentially increasing production up to 300%. To make proactive decisions and act on the recommendations generated from these production enhancement opportunities is still a challenge that needs to be addressed. For fields with large numbers of ESP wells a time snap of reservoir properties could be periodically obtained to track changes in pressure skin and permeability for real time optimization. Introduction One of the main objectives of every operating company is to optimize reserves in order to maximize their assets value. For the reservoir engineers in the brown fields (mature fields) the challenge in defining the exploitation strategy is the lack of critical reservoir information such as pressure and permeability. Many times old information based on few scattered measurements is propagated to make important decisions. In case of production engineers the continuous degradation in inflow due to skin affects their return on investment. For operations engineers operating artificially lifted systems the main concern is to make sure that equipment is running efficiently and to avoid catastrophic failures.SHELLSPE109053Well TestingConnected Volume EstimationPTAUse of Advanced Pressure Transient Analysis Techniques To Improve Drainage Area Calculations and Reservoir Characterisation: Field Case StudiesKui-Fu Du, SPE, NAM, The NetherlandsAbstract This paper presents several field examples of applying two independent methods of increasing tested area estimation and improving reservoir characterisation based on utilising the entire well test history rather than just a single pressure build-up (PBU) or drawdown period. The two techniques are the pressure-rate deconvolution and the conventional pressure transient analysis (PTA) based shrinking box approach. A large number of the field cases are studied to illustrate their benefits as well as procedures for the minimum tested area calculations under various reservoir geometries. These field examples demonstrate that both methods if carefully used can yield almost identical radii of investigation derived from the entire test sequence and that the deconvolution technique can reveal additional reservoir information which may not be detected otherwise. Introduction Well testing involves a process that creates an input signal normally a sudden disturbance in flow rate and measures the corresponding pressure change with time. It is one of the key sources of dynamic data that is used to assess and characterise the well-reservoir in question including determination of well deliverability skin permeability various reservoir heterogeneities boundaries and reservoir connectivity. These parameters are estimated on the basis of the constant rate drawdown (CRD) theories. Due to our inability to maintain flow rate constant the current PTA techniques are mainly based on the analysis of individual flow periods in isolation chiefly the longest PBU period in the test. However the whole test sequence usually comprising several cycles of flow/shut-in periods such as the one showed in Fig. 1 is much longer in duration and may contain more information about the reservoir than that the longest buildup or flow period does. In summary the current PBU analysis technique has the following well-known drawbacks: Gives a tested volume much less than that potentially investigated during the entire test; Does not reveal all the reservoir information that may be hidden in the entire test data; Leads to incorrect diagnosis of reservoir model under certain conditions merely due to the artifacts of late time pressure buildup derivative calculation. The paper presents the application of two novel methods to real-life examples that enable the whole duration of a well test to be analysed rather than on just a single flow period: 1. Deconvolution: This is not a new interpretation method but an advanced mathematical data preprocessing tool that removes effects of step-wise flow rate variation in a test (Note that this is different from the term of deconvolution used in the literature to remove the effect of wellbore storage). In other words it transforms a variable rate well test into a single CRD response over duration equal to the entire test time thereby overcoming the above-mentioned drawbacks of the traditional PBU analysis. Based on the deconvolved derivative response we can directly determine a larger area of investigation from the entire test history and recognise more distant reservoir features such as boundaries that may not be uncovered otherwise. Thus more information is obtained from the same dataset. 2. Conventional PTA Approach: This method manually infers the minimum tested area from the total test duration. It is achieved by firstly identifying a model that matches the entire test data under the known initial reservoir pressure then adding boundaries to close off any open-ended directions and progressively reducing the distance to these boundaries until the response of the closed model starts to deviate from that of the open-ended model. A large number of field case studies are presented to illustrate the key benefits and the procedures of the two advanced techniques. These field cases show that both methods if carefully used can give almost identical radius of investigation value Rinv derived from the entire test sequence and that the deconvolution technique can give additional reservoir diagnostics hence improving reservoir characterisation. The field examples also examine some key control parameters governing the outcome of the deconvolution algorithm and demonstrate how to estimate the minimum drainage area under various reservoir geometries.OnePetroBPIPTC11691Well TestingConnected Volume EstimationEvaluating Connected Reservoir Volume for Optimizing Reservoir Management in Farragon Field, an Offshore North Sea New DevelopmentJulio Herbas, SPE, Munawar Usman, SPE, Ronnie Parr and Jordy Buter, BP Exploration Operating Company LimitedAbstract The Farragon field discovered in April 2003 is a low relief pancake shaped reservoir located in the UK sector of the North Sea. This relatively small offshore field was developed with two sub-sea horizontal wells tied to existing production facilities. Initially the light 34API oil was produced by natural flow and subsequently gas-lift has been used for artificial lift. A few months after first oil the field was consistently achieving production rates higher than predicted which led to a decision to enhance the application of early extensive reservoir engineering studies aiming to better understand the reservoir mechanism volumes in place and their implications for field depletion plans. Data from permanent pressure gauges installed in the two open-hole gravel-packed horizontal producers was analysed to improve understanding of the reservoir. Average reservoir pressure productivity index and connected volume were interpreted from build-up & drawdown tests. The calculated oil in place volumes were history matched with multiple Material Balance runs which used BPs TDRM Top Down Reservoir Modelling1 process. This powerful tool is designed to evaluate reservoir engineering uncertainties in a wide range of scenarios considering multiple variables providing much greater confidence in the obtained results. Full field multidimensional numerical simulation models with updated volumes from new 3D seismic reinterpretations history matched the field performance confirming previous classical reservoir engineering conclusions. The outcome before the first 18 months of field life demonstrated the value of extensive application of reservoir and petroleum engineering techniques in a very early stage of the field life as it resulted in a 25% increase in estimated oil recovery. This paper outlines the general methodology applied that drove the implementation of optimized reservoir management strategies. Introduction Preliminary classical reservoir engineering studies performed on the Farragon field during the first year of oil production suggested a bigger than originally estimated volume of initial oil in place. This was in-line with the production performance which was consistently above the initial expectations. Basic Decline Curve Analysis Pressure Transient Test interpretations material balance and numerical simulation models demonstrated consistency with field trends and with analogous fields although the production period by the time the first studies were performed was quite short. Transient test data were interpreted to determine the reservoir properties and to estimate the connected volumes. Material balance provided oil in place results consistent with those from the pressure transient tests a quantitative insight into the production mechanism and water front displacement. Water breakthrough occurred in the deeper well # 2 6 months after 1st oil. The water cut was matched and the water breakthrough in the shallower well # 1 has been predicted to occur after some 20 months of the field production start. Full field numerical reservoir simulation studies were then performed confirming previous results from the classical reservoir engineering analyses. This provided the basis to justify an important increase in the field volumes and recoveries and for the initiation of further studies aiming to investigate alternate exploitation schemes to increase the final recovery further. Geology and Reservoir Description The Farragon reservoir lies in sands of Palaeocene age close to several existing fields: the mature Andrew and Cyrus fields to the South-West and the Arundel discovery to the North-West. The sediments were deposited in a submarine fan environment consisting of distal turbiditic facies. The reservoir thickness is up to 55 m gross (40 m net) limited at the top by a structural seal and at the bottom by a large aquifer of regional extent. The oil water contact is at 2556.5m TVDss. Figure 1 shows a depth map of one realisation of the four-way dip closed structure.BPSPE102483Well TestingConnected Volume EstimationThe Use of Well Testing for Evaluation of Connected Reservoir VolumeM.M. Levitan, SPE, and M.J. Ward, SPE, BP plc.; J.-L. Boutaud de la Combe, SPE, Total S.A.; and M.R. Wilson, Well-Test Solutions Ltd.Abstract In its search for new oil and gas reserves the oil industry moves to more and more remote areas of the world and to technically challenging areas of deep water. Development of hydrocarbon resources in these environments is extremely expensive. To be economically viable the newly discovered fields must be developed and effectively exploited with very few wells. This forces the oil companies to concentrate on high quality reservoirs that yield highly productive wells with large reserves per well. High costs prohibit extensive appraisal activity and drive development decisions based on very few wells. Whilst these limited penetrations are often logged extensively using modern formation evaluation tools the acquired static data cannot confirm that the wells will drain sufficient reserves. Evaluation of reservoir connectivity over large distances from the well requires relatively long and expensive well tests. In this paper we review a number of critical points associated with design and execution of such tests. The key here is to ensure that the data acquired during the test will contain sufficient information to draw conclusions about the reservoir connectivity and to estimate the reservoir volume that is in communication with the well. We discuss the well test sequences used for this purpose the tools and operational aspects of well test execution the data acquisition the well test analysis techniques the accuracy and the degree of uncertainty of test results. We illustrate this application of well testing for reservoir connectivity with several real test examples. Introduction Well testing is one of the techniques used for reservoir and well evaluation. Well testing studies dynamic reservoir behavior in response to changing flow conditions at the well. The dynamic reaction of well bottomhole pressure to rate changes depends on the reservoir and well properties. Hence studying the dynamic pressure behavior in response to appropriately designed sequence of well rate changes provides a way to evaluate some of these properties. This technique has been historically used for evaluation of formation permeability large-scale reservoir heterogeneities and boundaries reservoir connectivity well productivity and for diagnosing possible well productivity problems. Depending on test objectives a well test may last from several days to several weeks and even months. The longer the test the larger is the reservoir volume investigated during the test. When used for exploration and reservoir appraisal these tests normally involve flowing hydrocarbons to surface and disposal of some of these hydrocarbons through flaring. Completion of a reservoir appraisal well and subsequent well testing is a long and very expensive operation which carries significant operational risks. A decision to perform a well test and accept these costs and risks should only be supported if the test will provide the information that is critical to shaping the appropriate reservoir development plan. There are alternative techniques for evaluation of formation rock properties through well logging and the use of modern formation evaluation tools. These methods allow estimation of the short-term productivity of the well. However these techniques cannot confirm that the well is connected to a sufficiently large volume and will be able to drain sufficient reserves. Well testing still remains the only method for direct evaluation of reservoir connectivity over large distances from the well. Development of hydrocarbon resources in deep water environment is extremely expensive. To be economically viable the newly discovered fields must be developed and effectively exploited with very few wells. This forces the oil companies to concentrate on high quality reservoirs that yield highly productive wells with large reserves per well. Assessment of reservoir connectivity becomes one of the main objectives in appraisal of such fields. An appropriately designed and executed well test that confirms good reservoir connectivity may potentially decrease the total number of wells required for appraising the field and reduce the overall costs of the reservoir appraisal program.TOTALSPE102483Well TestingConnected Volume EstimationThe Use of Well Testing for Evaluation of Connected Reservoir VolumeM.M. Levitan, SPE, and M.J. Ward, SPE, BP plc.; J.-L. Boutaud de la Combe, SPE, Total S.A.; and M.R. Wilson, Well-Test Solutions Ltd.Abstract In its search for new oil and gas reserves the oil industry moves to more and more remote areas of the world and to technically challenging areas of deep water. Development of hydrocarbon resources in these environments is extremely expensive. To be economically viable the newly discovered fields must be developed and effectively exploited with very few wells. This forces the oil companies to concentrate on high quality reservoirs that yield highly productive wells with large reserves per well. High costs prohibit extensive appraisal activity and drive development decisions based on very few wells. Whilst these limited penetrations are often logged extensively using modern formation evaluation tools the acquired static data cannot confirm that the wells will drain sufficient reserves. Evaluation of reservoir connectivity over large distances from the well requires relatively long and expensive well tests. In this paper we review a number of critical points associated with design and execution of such tests. The key here is to ensure that the data acquired during the test will contain sufficient information to draw conclusions about the reservoir connectivity and to estimate the reservoir volume that is in communication with the well. We discuss the well test sequences used for this purpose the tools and operational aspects of well test execution the data acquisition the well test analysis techniques the accuracy and the degree of uncertainty of test results. We illustrate this application of well testing for reservoir connectivity with several real test examples. Introduction Well testing is one of the techniques used for reservoir and well evaluation. Well testing studies dynamic reservoir behavior in response to changing flow conditions at the well. The dynamic reaction of well bottomhole pressure to rate changes depends on the reservoir and well properties. Hence studying the dynamic pressure behavior in response to appropriately designed sequence of well rate changes provides a way to evaluate some of these properties. This technique has been historically used for evaluation of formation permeability large-scale reservoir heterogeneities and boundaries reservoir connectivity well productivity and for diagnosing possible well productivity problems. Depending on test objectives a well test may last from several days to several weeks and even months. The longer the test the larger is the reservoir volume investigated during the test. When used for exploration and reservoir appraisal these tests normally involve flowing hydrocarbons to surface and disposal of some of these hydrocarbons through flaring. Completion of a reservoir appraisal well and subsequent well testing is a long and very expensive operation which carries significant operational risks. A decision to perform a well test and accept these costs and risks should only be supported if the test will provide the information that is critical to shaping the appropriate reservoir development plan. There are alternative techniques for evaluation of formation rock properties through well logging and the use of modern formation evaluation tools. These methods allow estimation of the short-term productivity of the well. However these techniques cannot confirm that the well is connected to a sufficiently large volume and will be able to drain sufficient reserves. Well testing still remains the only method for direct evaluation of reservoir connectivity over large distances from the well. Development of hydrocarbon resources in deep water environment is extremely expensive. To be economically viable the newly discovered fields must be developed and effectively exploited with very few wells. This forces the oil companies to concentrate on high quality reservoirs that yield highly productive wells with large reserves per well. Assessment of reservoir connectivity becomes one of the main objectives in appraisal of such fields. An appropriately designed and executed well test that confirms good reservoir connectivity may potentially decrease the total number of wells required for appraising the field and reduce the overall costs of the reservoir appraisal program.SHELLSPE115720Well TestingConnected Volume EstimationMagnetic Resonance in Chalk Horizontal Well Logged With LWDArve K. Thorsen, SPE, Tor Eiane, SPE, and Holger Thern, SPE, Baker Hughes, and Paal Fristad and Stephen Williams, SPE, StatoilHydro ASAAbstract This paper describes geological and petrophysical evaluation of a new structure of a mature field to evaluate the reservoir potential in un-produced reservoir zones. The well was drilled in a carbonate with variations in rock quality and with minor sub-faulting occurring. Gamma Resistivity Density Neutron and Image services were used in the horizontal part of the well in addition to Magnetic Resonance. To achieve the best possible real-time wellbore placement reservoir navigation and continuous follow-up on the horizontal log interpretation was performed during drilling. For the first time a low gradient Magnetic Resonance (MR) while drilling technology was deployed in a virgin carbonate horizontal well on the Norwegian Continental Shelf. The MR Service was run to obtain porosities (incl. partitioning of movable and bound fluids) HC saturations and permeability estimates. Fluid saturations based on traditional methods and the MR were evaluated and compared by core data enhancing the understanding of the measurement and the reservoir. For post-processing the MR data were integrated and interpreted together with the other measurements performed in the well delivering an accurate and consistent reservoir description. First part of the horizontal part of the well was drilled with conductive drilling fluid and the latter part with non-conductive drilling fluid. Lab measurements for the two mud filtrates were performed to understand the influence of the two different drilling fluid types on the MR measurements. In the absence of oil based mud filtrate invasion the MR data show better agreement with saturations from core confirming the quality and reliability of the MR data. Comparison of the MR T2 distribution and volumetric with image data indicates that even fine variations in rock quality and lithology are reliably resolved by the MR data. Prior to logging old core data was used to refine the constants used in the Timur-Coates MR permeability equation. MR permeability showed changes in reservoir quality. Values will be calibrated when Timur-Coates constants are derived from the core plugs from this well. Introduction The Oseberg field is located in the northern part of the North Sea 130 km NW of Bergen Norway. The sea depth in the area is 100 metersi.BPSPE102484Well TestingDeconvolutionDeconvolution of Multiwell Test DataMichael M. Levitan, SPE, BP plcSummary The deconvolution analysis technique that evolved with development of the deconvolution algorithms by von Schroeter et al. (2004) Levitan (2005) and Levitan et al. (2006) became a useful addition to the suite of techniques used in well-test analysis. This deconvolution algorithm however is limited to the pressure and rate data that originate from a single active well on the structure. It is ideally suited for analysis of the data from exploration and appraisal well tests. The previously mentioned deconvolution algorithm can not be used with the data that are acquired during startup and early field development that normally involve several producing wells. The paper describes a generalization of deconvolution to multiwell pressure and rate data. Several approaches and ideas for multiwell deconvolution are investigated and evaluated. The paper presents the results of this investigation and demonstrates performance of the deconvolution algorithm on synthetic multiwell test data.