The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Ashraf, Qasim (Weatherford International Ltd.) | Khalid, Ali (Weatherford International Ltd.) | Luqman, Khurram (Weatherford International Ltd.) | Hadj-Moussa, Ayoub (Weatherford International Ltd.) | Shafique, Muhammad Bilal (MOL Pakistan Oil & Gas Co. B.V.) | Abbas, Khurram (MOL Pakistan Oil & Gas Co. B.V.) | Tashfeen, Muhammad (MOL Pakistan Oil & Gas Co. B.V.) | Khan, Shahjahan (MOL Pakistan Oil & Gas Co. B.V.) | Jameel, Rizwan (MOL Pakistan Oil & Gas Co. B.V.)
Abstract The Northern Potwar Plateau of Pakistan is known for its severe geological features. Many wells have been drilled in the region, but geological correlations in neighboring fields have proven to be challenging. Excessive tectonic activity and faults have resulted in formation repetitions, abnormal in-situ stresses, and variable formation pore and fracture pressures. One such field in the region is MDK field, where the operator was in the process of drilling a second well. Drilling of the 8 ½-in. hole section was in progress at 11,004 ft. (3,354 m) when the Bahadur Khel Salt formation was encountered. Upon drilling further into the formation, the operator encountered severe hole stability issues coupled with lost circulation. While in the salt formation, whenever circulation was stopped and annular pressure losses were eliminated, the drill string would become stuck. Upon resuming circulation, the pumping pressure would rise abruptly. The formation was highly stressed and was exhibiting a creeping behavior. Any reduction in the bottom hole pressure (BHP) would cause the formation to creep into the wellbore. The operator spent a month attempting to drill through the highly stressed plastic salt formation, without success. The oil-based mud system was already weighted up to its maximum, and no other conventional means existed of controlling the creeping salt. The operating company had already spent ~USD 19 million dollars on the well, and was considering abandoning it after a nearby well in the same formation had been abandoned despite four unsuccessful sidetracks. Maintaining a constant bottom hole pressure (CBHP) across the formation at all times was the only way to stabilize the salt formation and lost circulation treatment. Only managed pressure drilling (MPD) could achieve the application of CBHP. An MPD system would enable the operator to compensate for the lack of BHP by applying surface backpressure, thereby maintaining the target pressure across the formation at all times. With the help of the MPD system, the operator also sought to calculate the formation creep rate, so as to evaluate a time window for running in and out of the hole. Besides drilling, the operator also intended to isolate the challenging section with a liner. With proper planning, the MPD system could help to achieve this objective. A full MPD system was deployed to the wellsite and drilling resumed with a CBHP in dynamic and static periods. By CBHP MPD, the operator was able to tag bottom. Drilling and underreaming of the 8 ½-in. hole section resumed and continued until reaching the target depth of 14,745 ft. (4,494 m). After drilling, the 7-in. liner was set and cemented to the target depth using MPD. Applying CBHP MPD enabled the operator to drill through 3,832 ft. (1,168 m) of the hole section and save the well from abandonment. This paper studies the design, execution, and lessons learned when applying MPD on the subject well.
Tian, Yi (HCML) | Yustendi, Kiki (HCML) | Lian, Jihong (HCML) | Etuhoko, Michael (HCML) | Soufanny, Alfon (HCML) | Jiang, Kai (CNOOC International Limited) | Luo, Limin (CNOOC International Limited) | Xiang, Ming (CNOOC International Limited) | Chang, Congbing (CNOOC International Limited) | Diemert, Anthony Paul (Husky Energy)
Abstract BD Gas Field is located in offshore in the Madura Strait, Indonesia, and has a total of four producing wells - one vertical (Well Y1) and three horizontal (Well Y2, Well Y3, and Well Y4) from an unmanned platform. Its reservoir was considered near HPHT and critical sour with 8,100 psi bottom hole pressure, 300°F bottom hole temperature, 5.5% CO2 and 5,000 ppm H2S. This paper highlights on the Company journey to maintain well integrity during well design phase, well construction phase, and production phase of BD Gas Field. During well design phase, material selection and design for 9-5/8 in. intermediate casing, 7 in. production casing, and 4-1/2 in. tubing were based on the expected life of the well and reservoir properties in accordance to the requirements of NACE. Cementing design for 7 in. production casing cement was tested and analyzed in the laboratory for 60 days in the HPHT chamber simulating reservoir properties. Top of cement was designed to the mud line to minimize wellhead growth. Completion design was monobore type and divided into lower, intermediate, and upper completion strings. All packers were V-0 (zero bubble) rating. Maintaining well integrity during well construction phase was challenging. Batch drilling and completion was applied, and at all times, the wells were required to be suspended with proper and adequate barriers. During drilling and well clean-up phase, inter-casing pressure management (i.e., annulus pressure, wellhead growth monitoring, bleed off program, etc.) was implemented to maintain the casing and tubing integrity. During production phase, routine wellhead growth measurement, constant monitoring and bleed off program were developed and communicated with related departments. Pressure control valves and alarm system were installed and tested to the annulus. In additional to the wellhead growth, transverse wellhead movement was observed in one of the wells especially during rough sea conditions. In order to reduce the tranverse wellhead movement which may induce more stress on the surface pipings and connections, it was planned to install under water shims in between the conductor pipe and platform jacket guide funnel. Some surface piping and platform modification were also considered because wellhead growth leads to limitations on gas production to prevent safety issues.
YIN, Qishuai (China University of Petroleum) | YANG, Jin (China University of Petroleum) | ZHOU, Bo (CNPC Drilling Research Institute) | JIANG, Menglei (China University of Petroleum) | CHEN, Xiaoliang (China University of Petroleum) | FU, Chao (China University of Petroleum) | YAN, Li (China University of Petroleum) | LI, Lei (China University of Petroleum) | LI, Yatao (China University of Petroleum) | LIU, Zhengli (CNOOC, China Limited, Shenzhen Branch)
Abstract Today's data is tomorrow's oil and gas. Only the data can tell us right or wrong, but not the experience or feel. The real-time logging data conforms to the 6V features of the Big Data (Velocity, Variety, Volume, Veracity, Visualization and Validity). As a result, the drilling operations efficiency is significantly improved by the Big Data mining of real-time logging. The Big Data mining helps recognize the drilling operations automatically and identify the invisible non-production time (INPT). Firstly, the real-time logging data is acquired by the comprehensive logging unit. Secondly, the drilling operations are recognized by applying restrictions to drilling parameters. Thirdly, the daily time and the total time is breakdown based on the above logging data and operations categories. Finally, the INPT is identified by setting the target value based on the Big Data mining and learning curve. The savings potential, which is determined by the average and target, is critical to improve the operations efficiency. On one hand, the Normal Distribution is established by setting the specific operation time (such as slips connection time, etc.) to the X-axis and the operation count to the Y-axis. The average and covariance of the Normal Distribution is calculated. On the other hand, the target value is based on the Big Data mining by the Bayesian network model and the total-time learning curve of batch wells. As a result, the real-time drilling efficiency can identify the best-performing operations, crews and rigs. The crew-based operational performance comparisons are effective to identify the best-performing crews and to indicate where best to focus training and crew supervision efforts in the future. And the real-time drilling efficiency can measure the rig performance in order to make INPT visible. At last, the real-time drilling efficiency yields cost and time savings on both deep-water and complex wells. The method is successfully applied to BD gas field in Indonesia which is HTHP and LW oil field in South China Sea which is in deep-water. Application shows the INPT represents about 32%. The Big Data mining of real-time logging significantly improve the drilling operations efficiency, detect and minimize the INPT. As a result, the Big Data mining yields cost and time savings for tomorrow's market.
Rizkiani, D.. (HCML) | Yustendi, K.. (HCML) | Rusli, B.. (HCML) | Mbouw, A. N. (HCML) | Mcken, D. R. (HCML) | Effendi, H.. (Baker Hughes) | Zulkarnain, S.. (HCML) | Soufanny, A.. (HCML) | Yang, Z.. (HCML) | Tian, Y.. (HCML) | Lian, J.. (HCML) | Maladi, A.. (Husky) | Diemert, A. P. (Husky) | Fadil, M.. (SKK Migas) | Utomo, P. P. (SKK Migas) | Yudento, S. D. (SKK Migas) | Mahry, A.. (SKK Migas)
Abstract BD Field is the first development project of Husky-CNOOC Madura Limited (HCML) in Madura Strait, Indonesia which has a pressure of 8,100 psi and a temperature of 300°F. This Kujung gas reservoir contains of 5.5% CO2 and 5,000 ppm H2S, indicating that the reservoir is near High Pressure High Temperature (HPHT) and critical sour environment. This paper describes the best practices, lessons learned and strategy to control drilling issues such as slim hole, horizontal, near High Pressure-High Temperature, high density, and sour/acid gas environment to achieve the well TD with torque and ECD limitation, without compromising production target. Kujung reservoir section was drilled with an overbalance mud system as per CNOOC HPHT and sour well requirement. Drill-In fluid (DIF) system treated with potassium formate and manganese tetraoxide as weighting agents was chosen for drilling the 5-7/8-in. reservoir section. Throughout the drilling operation, higher torque and ECD value was identified compared with Torque and Drag (T&D) Calculation and Hydraulics simulation. This can lead to shallower TD decision, which has consequence of possibility not achieving initial target depth/production. Calibrating T&D model using the pickup/rotate/slack-off value from actual measurements on both cased and open holes was done in order to match the model with actual condition. Several analysis and review of all possible causes was performed, including performance of solids control equipment, inadequate hole cleaning, dog leg severity, wellbore direction and/or formation lithology changes. T&D and hydraulics simulation was also performed to foresee the possible operation limitation with several lateral lengths to ensure having successful drilling operation without compromising both operational safety and future well production. Based on the original model, with friction factor values of 0.25 (cased hole) and 0.35 (open hole), 1000-1500 ft lateral length of 5-7/8-in. slim hole section can be achieved. However, with calibrated T&D model, friction factor values were almost double the original model. Comprehensive planning was done to accomplish the drilling objectives, such as re-plan well trajectory to reduce dog leg severity, selection of drill fluid lubricant additives to ensure its stability at pH > 11 environment as planned to control sour gas and compatibility with other products, maximize centrifuge usage to minimize excessive LGS build-up caused by successive and repetitive mud system re-use for batch drilling operations, and diluted system using rehabilitation mud. Reduced friction factors and decreased torque values were the key parameters to successful drilling through the updated planned horizontal length. In terms of gas well production, the objective of well productivity was achieved during unloading operation when gas production result from the wells yielded higher Absolute Open Flow (AOF) as compared to the planned target. Hence a successful BD wells had been delivered to production.
Lian, J.. (Husky CNOOC Madura Limited) | Tian, Y.. (Husky CNOOC Madura Limited) | Yang, Z.. (Husky CNOOC Madura Limited) | Yustendi, K.. (Husky CNOOC Madura Limited) | Rizkiani, D.. (Husky CNOOC Madura Limited) | Nurdin, S.. (Husky CNOOC Madura Limited) | Mcken, D. R. (Husky CNOOC Madura Limited) | Etuhoko, M. O. (Husky CNOOC Madura Limited) | Jiang, K.. (CNOOC International Ltd.) | Diemert, A. P. (Husky Energy Inc.) | Fadil, M.. (SKKMigas) | Utomo, P. P. (SKKMigas) | Mahry, A.. (SKKMigas) | Yudento, S. D. (SKKMigas)
Abstract The Company had successfully drilled 4 challenging BD Development Wells (1 vertical and 3 horizontal). BD Field reservoir is aKujung 1 limestone reef, considered near HPHT and critical sour with 8,100 psi Bottom Hole Pressure (BHP), 300℉ Bottom Hole Temperature (BHT), 5.5% CO2 and 5,000 ppm H2S. This paper highlights the design phase and well deliverability covering pressure window, casing design, material selection, wellhead and Christmas tree, directional drilling planning, drilling fluid, cementing consideration, well completion, annulus pressure management, and project challenges. The data from two offset wells with surface location radius fewer than 2,000 ft from BD Platform were used as reference for lessons learnt and design for the casing seat selection. Based on the Wellbore Stability Study and the offset wells data, there exists a narrow mud weight window between pore pressure and fracture pressure. The directional plan was developed to have sufficient well separation in the upper hole section and enable fewer dog leg severity requirement to drill in the down hole section. Material selection for casing was designed based on the expected life of the well and reservoir properties in accordance to the requirements of NACE. Drill-in fluid system (Potassium Formate and Manganese Tetraoxide) with mud weight of 14.9 ppg was used to drill the limestone reservoir section providing minimal damage to the reservoir. Production casing cement was tested and analyzed in the laboratory for 60days in the HPHT chamber simulating reservoir properties. Open Hole Monobore Completion approach was selected to complete the well. In order not to compromise well integrity, annulus pressure management technique was fully implemented during drilling, completion, and well clean up phases. The wells were successfully executed despite several challenges which required unique mitigations to manage. During well clean ups, all wells were able to exceed the Absolute Open Flow (AOF) expectations.
Nurdin, M. S. (Husky-CNOOC Madura Ltd.) | Etuhoko, M. O. (Husky-CNOOC Madura Ltd.) | McKen, D. R. (Husky-CNOOC Madura Ltd.) | Lian, J.. (Husky-CNOOC Madura Ltd.) | Syapari, A.. (Baker Hughes) | Nuryadi, H.. (Baker Hughes) | Fadil, M.. (SKK Migas) | Utomo, P. P. (SKK Migas)
Abstract BD is a near high pressure-high temperature (HPHT) critical sour gas field located in offshore Madura Strait in water depth of 152 ft. An exploration and appraisal well were drilled in 1987 and 1992 respectively, targeting BD reef at depth of 10,676ft SSTVD. Both well test results confirmed the limestone formation has characteristic of 305°F and 8,105 psi, with 5,000 ppm of H2S and 5.5% of CO2 content. Four (4) development wells including three (3) horizontal and one (1) vertical well, were drilled to drain the reserves from BD field. The project was expected to deliver 120 MMSCFD of gas and 6,000 bpd of condensate for a period of 15 years production from BD field. Design, equipment and material to complete the well need to meet the target and be selected based on industry guidance and the environment to ensure the integrity of the well during the production time. Completion for BD wells adapts multiple tie-back concept to provide consistent large flow area and big bore advantages, providing flexibility for future well intervention. It consists of 3 (three) main assemblies and was designed based on series of load cases to predict the completion reliability to withstand the load during the life of the well. During the installation, the assemblies were run in different batches and fluid environment. Despite the challenges encountered during the preparation and installation, all wells were successfully completed and cleaned up safely without any incident. The completion could exceed the initial production target set by the reservoir engineering team. This paper will discuss about the completion process from the first near HPHT sour field development project in Indonesia. It describes the design process, preparation and installation of the BD completion especially in the horizontal well. Challenges, basis of design, material selection, lessons learned and optimization taken to safely deliver the completion are also covered in this paper.
Yin, Qishuai (China University of Petroleum) | Yang, Jin (China University of Petroleum) | Liu, Shujie (CNOOC) | Sun, Ting (China University of Petroleum) | Li, Wenlong (China University of Petroleum) | Li, Lilin (China University of Petroleum) | Hu, Nanding (China University of Petroleum) | Tong, Gang (China University of Petroleum) | Chen, Xiaoliang (China University of Petroleum) | Deng, He (China University of Petroleum)
Abstract The proposed intelligent method, which is based on the pressure data and the spatial location of the adjacent drilled wells, and the spatial continuity of the targeted region, is able to establish the formation pressure profile with credibility, the safe window with credibility of drilling fluid density, the probability profile of drilling risk and the risk interval of drilling operation. As a result, the proposed method achieves the intelligent identification of drilling risk in complex formations. In this intelligent method, the concept of formation pressure matrix is introduced firstly, and an epitaxial stratigraphic pressure migration algorithm is established to calculate the pressure of the targeted wells in the same tectonic region based on the depth adjustment and the inverse distance weighting algorithm. Secondly, the probability of drilling risk is calculated. Thirdly, the membership function of different degree interval is constructed by fuzzy mathematics theory combining with the accident record of drilled wells; and finally, divide the membership degree of drilling operation risk to achieve the intelligent identification of drilling risk. The intelligent method has been successfully applied in BD gas field in Indonesia. Nine drilling accidents such as kicks, collapses, leakages and stickings have been accurately identified in a certain well. The formation pressure of adjacent drilled wells is transplanted to the targeted wells and the pressure prediction is more accurate. Meanwhile, combined with the accident records of drilled wells, the intelligent identification of drilling risk can be carried out. The two issues mentioned above have been the focus of researchers. Under normal circumstances, the designers use stratigraphic comparison method, in which the formation pressure of the drilled wells is directly applied to the targeted well and does not consider the spatial distribution characteristics of the targeted formation. And the designers cannot intuitively determine the possibility of drilling risk according to the numerical drilling risk probability value. This intelligent method gives the transplantation method calculating the formation pressure of the targeted well in the same tectonic region and divides the drilling risk interval. This method has been used to analyze the risks in BD gas field in Indonesia and the LW oil field in South China Sea. Case studies were carried out to verify the method, in which the predicted formation pressure was compared with that derived from the LWD. The results showed that the maximum relative errors were within 2.76%. Example analysis showed that the identifying result of this method agreed with the actual engineering. The identification results of proposed intelligent method agrees with the engineering practical situation, satisfies the need of drilling engineering and can provide basis for identifying risk in drilling design.
Abstract The Maleo Producer is located in the Santos' Maleo Field in the Madura Straits, Indonesia. The site is located near the southeastern tip of the Madura Island, north of Java in an area of active tectonics. The driving mechanism for earthquakes in this region is the Sunda Arc subduction zone, a 5,600 km long zone of seismic activity that defines the tectonic boundary between the Indian Ocean part of the Australian tectonic plate and the continental crust of the Eurasian tectonic plate. The Maleo Field is underlain by very soft normally consolidated highly plastic lightweight marine clay requiring a detailed site response analysis that included modeling of soil structure interaction. This paper discusses the development of seismic design criteria for the project and the input parameters for analyses of successively increasing complexity for the evaluation of the platform. The seismic design criteria included development of site-specific seabed response spectra for different return periods for an initial set of response spectrum analysis followed by the development of acceleration time histories for use in the detailed non-linear soil-structure interaction model. The paper also discusses practical considerations in the development of time histories to facilitate reasonable runtime for the global soil-structure interaction analyses. Introduction This paper presents the results of a site-specific seismic hazard study for the development of seismic design criteria for the Maleo Producer platform located in Madura Straits, Indonesia. The site is located near the southeastern tip of the Madura Island, north of Java. The general location of the site is shown in Figure 1. The seismic design criteria were developed for assessing the seismic stability of the platform meet the class requirements of American Bureau of Shipping (ABS, 1997). The seismic analysis methodology and the development of seismic design criteria followed the general guidelines of American Petroleum Institute's API RP2A (API, 2000). Accordingly, site-specific response spectra and acceleration time histories were developed for Strength Level Earthquake (SLE) and Ductility Level Earthquake (DLE) for an increasingly complex set of structural analyses (Jacob and Stewart, 2008 and Templeton, 2008). The analysis ranged from linear elastic response spectrum analysis to nonlinear fully coupled soil-structure interaction analysis. The seismic design criteria and the methodology employed for the development of the SLE and DLE spectra and acceleration time histories were independently evaluated and accepted by the class society. Background The Maleo Producer was originally designed as a mobile offshore drilling unit (MODU). The platform is a 1970's vintage mat supported jack-up (designated as the Cliff's Drilling - CD10) that was converted to a mobile offshore production unit (MOPU) in 2005-2006 to operate as a gas production platform in the Santos' Maleo Field in the Madura Straits. Prior to conversion, the Maleo Producer was operating in the Arabian Gulf. Following conversion, it was dry towed from the Arabian Gulf to its current operating location. The site is located in an area of active tectonics defined by the Sunda Arc subduction zone, which is capable of generating very large earthquakes such as the December 2004, Magnitude 9.3, Banda-Ache earthquake. The original design of the platform did not include seismic loading. However, seismic evaluation of the platform was a requirement of class approval for its current operation. This paper discusses the development of seismic design criteria in terms of site-specific response spectra and acceleration time histories for use in the structural analysis of the Maleo Producer.
Abstract The Maleo Producer is a converted Bethlehem JU250 mat-supported jack-up unit, which was installed in July 2006, on a soft, normally consolidated clay foundation some 40 km (25 mi) south east of Madura Island and approximately 25 km (16 mi) south of Puteran Island, offshore Indonesia. The unit was connected to a wellhead platform, and gas production began in late 2006. An initial site investigation performed in 2003 indicated that the undisturbed soil conditions consisted of a soft normally consolidated clay profile, with an undrained shear strength of 2 kPa (40 psf) at the mudline, linearly increasing with depth at a rate of 1.22 kPa/m (7.83 psf/ft) down to a depth of around 14 m (46 ft), below which a slightly stronger clay was encountered. The issue of on-bottom stability of the unit and its resistance to overturning were questioned by the classification society (ABS) as part of the reclassification of the rig. The behavior of the foundation under extreme storm loads and seismic events could be more reliably predicted by the designer, and more readily accepted by ABS, if new soil data were available. Two types of soil data were required 1) soil data for foundation design and re-analysis under and around the mat and 2) soil data for seismic analysis of the installation. This paper describes the extensive site characterization undertaken to prove the stability of the Maleo Producer facility during both the design storm and seismic events. Introduction The Maleo Field is located in Indonesian waters about 40 km (25 mi) south east of Madura Island and approximately 25 km (16 mi) south of Puteran Island (Figure 1), within the Madura Offshore Production Sharing Contract (PSC) area. The Maleo Producer is a converted Bethlehem JU250 mat-supported jack-up unit (formerly the CD10) ABS Class Number 7900120. The unit was installed in July 2006, and was connected to a wellhead platform. Gas production began in late 2006 (Figure 2). Description of the Installation The installation is in approximately 57-m (187-feet) water depth. The hull is supported on three cylindrical steel legs, 3.66-m (12-ft) in outer diameter. The legs are supported on an "A" shaped mat (Figure 3) that rests on the seafloor. The mat is 64 m (210 ft) long, 52 m (170 ft) wide and 3-m (10-ft) thick. It has 0.6-m (2-ft) deep skirts (extensions of the mat side walls) that extend along all edges of the mat (around the outside mat edges, inside the slot at the aft end and around the inside edges of the 18 m × 33m (59 ft × 108 ft) cut-out within the three legs beneath the hull (Figure 3). A 14-in (366-mm)-diameter gas export seafloor pipeline connects the installation (from the starboard side of the mat) to the 26-in. (660-mm) East Java seabed pipeline approximately 7 km (4.3 mi) to the south. Details of the structure's geometry, preload history, and design load conditions were provided by Stewart Technology Associates (2006 a&b), as documented in Ooley and Stewart (2008).
Summary In this paper we present a method to integrate well test, production, shut-in pressure, log, core, and geological data to obtain a reservoir description for the Pagerungan field, offshore Indonesia. The method computes spatial distributions of permeability and porosity and generates a pressure response for comparison to field data. This technique produced a good match with well-test data from three wells and seven shut-in pressures. The permeability and porosity distributions also provide a reasonable explanation of the observed effects of a nearby aquifer on individual wells. As a final step, the method is compared to an alternate technique (object modeling) that models the reservoir as a two-dimensional channel. Introduction The Pagerungan field has been under commercial production since 1994. This field was chosen to test a method of integrating dynamic well data and reservoir description data because the reservoir has only produced single phase gas, one zone in the reservoir is responsible for most of the production, and good quality well-test, core, and log data are available for most wells. The method that was used to perform the inversion of the spatial distribution of permeability and porosity uses a parameter estimation technique that calculates the gradients of the calculated reservoir pressure response with respect to the permeability and porosity in each of the cells of a reservoir simulation grid. The method is a derivative of the gradient simulator approach and is described in Appendices A and B. The objective is to find sets of distributions of permeability and porosity such that the calculated response of the reservoir closely matches the pressure measurements. In addition, the distributions of permeability and porosity must satisfy certain constraints given by the geological model and by other information known about the reservoir. Statement of Theory and Definitions The process of obtaining a reservoir description involves using a great amount of data from different sources. It is generally agreed that a reservoir description will be more complete and reliable when it is the outcome of a process that can use the maximum possible number of data from different sources. This is usually referred to in the literature as "data Integration." Reservoir data can be classified as "static" or "dynamic" depending on their connection to the movement or flow of fluids in the reservoir. Data that have originated from geology, logs, core analysis, seismic and geostatistics can be generally classified as static; whereas the information originating from well testing and the production performance of the reservoir can be classified as dynamic. So far, most of the success in data integration has been obtained with static information. Remarkably, it has not yet become common to completely or systematically integrate dynamic data with static data. A number of researchers, are studying this problem at present. This work represents one step in that direction. Well Testing as a Tool for Reservoir Description. Traditional well-test analysis provides good insight into the average properties of the reservoir in the vicinity of a well. Well testing can also identify the major features of relatively simple reservoirs, such as faults, fractures, double porosity, channels, pinchouts, etc. in the near well area. The difficulties with this approach begin when it is necessary to use the well-test data on a larger scale, such as in the context of obtaining a reservoir description. One of the main reasons for these difficulties is that traditional well-test analysis handles transient pressure data collected at a single well at a time, and is restricted to a small time range. As a result, traditional well-test analysis does not make use of "pressure" events separated in historical time. The use of several single and multiple well tests to describe reservoir heterogeneity has been reported in the literature, however, this approach is not applied commonly because of the extensive efforts needed to obtain a reservoir description. The method presented in this paper uses a numerical model of the reservoir to overcome these shortcomings. It will be shown that pressure transients can be used effectively to infer reservoir properties at the scale of reservoir description. Well-test data, both complete tests and occasional spot pressure measurements, will be used to this effect. The well-test information allows us to infer properties close to the wells and, when combined with the shut-in pressures (spot pressure), boundary information and permeability-porosity correlations, provides the larger scale description. General Description of the Method The proposed method is similar to other parameter estimation methods and thus consists of the following major items: the mathematical model, the objective function and the minimization algorithm. Mathematical Model. Because of the complexity of the reservoir description, the reservoir response must be computed numerically. Therefore, the pressure response is found using a numerical simulator. The reservoir is discretized into blocks. The objective is to find a suitable permeability-porosity distribution so that values of these parameters can be assigned to each of the blocks.