Well-testing Operations Research Articles

Study Explores Cost-Effective, Ecologically Sound Fluid-Disposal Methods

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202917, “Cost-Effective and Ecologically Sound Fluid Disposal During Well Cleanup and Post-Fracturing Flowback Operations,” by Yakov Shumakov, Florian Hollaender, SPE, and Bertrand Theuveny, SPE, Schlumberger. The paper has not been peer reviewed. The complete paper summarizes the results and lessons learned from the application of different methods used for fluid disposal in a wide range of well-testing operations around the globe. These were used to determine that economical and environmentally responsible solutions exist for fluid disposal during these operations. The complete paper also details a field-proven and cost-effective fluid-storage solution using a shuttle tanker during well-test and flowback operations offshore. Fluid-Disposal System Ecologically sound and safe fluid disposal during well testing and cleanup is one of the primary objectives, from an operational standpoint, of any temporary surface well-test package. Each fluid-disposal system is designed and sized for each operation according to the expected operating conditions. Typical fluid-disposal systems include the following. Water-Filtration System. In this system, produced water is first separated from hydrocarbons at the surface by using the well-test separator included in the temporary surface package; then, it is treated to remove as much oil as possible before discharge overboard. Even after effective treatment, however, produced water still contains traces of oil at parts-per-million levels. Overboard discharge of any kind is controlled strictly by environmental regulators and legislation. The primary pollutants of concern are hydrocarbons and grease; therefore, most treatment technology for water produced offshore is geared toward removing these contaminants. Mobile water-treatment systems are ideal for fast-response or urgent situations, as well as supplemental or temporary operations such as completions, workovers, or well testing. They are often used to assist during plant startup and maintenance outages when the water-treatment system is unavailable or cannot meet water-production requirements. Temporary Fluid Storage. Provisional storage of produced hydrocarbons has been used successfully in the past and is still considered an optimal solution for operations with a relatively small volume of liquid hydrocarbons produced. In offshore operations, one important factor beyond the space on the deck of offshore rigs is the limit on the volume of live crude that can be stored permanently on the rig. The limitation in recoverable liquid volume applies a significant constraint on the duration of the test; thus, this disposal technique is applicable mainly on gas wells and in environmentally sensitive areas.

Deep-Learning Technique Monitors Well-Testing Burner Efficiency

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19714, “Deep Learning for Monitoring Well-Testing Burner Efficiency,” by Darine Mansour, SPE, Hakim Arabi, and Yingwei Yu, SPE, Schlumberger, et al., prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. During well-testing operations, incorrect burner combustion could have an adverse effect on the environment or personal safety. Combustion efficiency is assessed by personnel who observe the flame. This practice lacks consistency and poses challenges, including environmental and safety considerations and issues with data. In the complete paper, the authors propose a solution that uses a deep neural network that learns from flame videos to define the quality of the combustion. The results are promising and show that this solution is a good candidate for real-time burner-efficiency monitoring and automatic alarm triggering and optimization. Introduction Automation of the evaluation of combustion efficiency would promote consistent combustion efficiency and timely reaction to undesirable combustion. In field operations, cameras are positioned for a direct view of the burner flames. The authors use a data set of video images captured by the cameras and labeled by domain experts as images of acceptable or undesirable combustion. The goal of the study is to automate human monitoring of the combustion by processing these images and classifying them automatically as images of acceptable or undesirable combustion. A supervised learning approach is applied to the problem. The approach consists of extracting the flame features from each image and feeding the features to a classifier that categorizes the combustion. The classifier is trained using the extracted features and labeled combustion images as input. The traditional approach to feature extraction is manual feature engineering, involving the extraction of handcrafted features using image-processing algorithms and domain knowledge. The process is tedious and time-consuming. Much effort is required to extract all relevant features in various contextual and environmental conditions. The extracted features are problem-dependent, and the process may require revisiting algorithms to adapt to new data that hold new features or new representations of existing features. Approach To achieve classification, a convolutional neural network (CNN) is trained using a data set of images labeled by domain experts. Using the image data set captured by well-testing cameras, a CNN with an architecture similar to VGG-16 that learns to extract powerful features from natural images is fine-tuned.

Extensive Well-Testing Operations Provide Insight Into Khuff Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203441, “Lessons Learned From Extensive Well-Testing Operations in Khuff Formations Offshore Abu Dhabi,” by Florian Hollaender, SPE, Schlumberger, and Mahmoud Basioni and Ahmed Yahya Al Blooshi, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. An extensive appraisal campaign was performed in the Khuff reservoirs offshore Abu Dhabi, with multiple appraisal wells drilled in different fields. Those wells were evaluated using detailed logging campaigns and then subjected to well tests, usually through drillstem testing for targeted intervals. The interpretation of well tests, combined with advanced petrophysical analysis, formation-test data, and production logs, provided insight into the nature of the Khuff reservoirs. A wide range of responses was observed, from tight to highly productive, but not necessarily with clear previous indications of deliverability or inflow intervals. Overview of the Khuff Formations The key characteristics of the Khuff formations offshore Abu Dhabi have been well-documented in previous work and can be summarized by the following: Low porosity and permeability carbonate reservoirs, where natural fractures are critical contributors to flow Properties vary widely laterally, with significant uncertainty regarding connectivity Variations in stress and petrophysical properties can be significant and affected by diagenetic and tectonic history These reservoirs present significant challenges for development planning. Previous studies have shown that it can be difficult to relate production performance to standard petrophysical analysis directly and that the presence of fractures - in particular, critically stressed fractures - in the vicinity of the wellbore is an essential factor for production performance. Productivity also was found to vary by several orders of magnitude within the same reservoir depending on the field and lateral location of a given well. The presence of natural fractures has been recognized as a major contributor to flow in tight gas reservoirs; however, this raises several questions related to assessing formation potential. First, the nature of the fractures must be evaluated. Some will contribute to production, while others will remain sealed. Equally importantly, identifying zones with promising porosity developments is not a solid indicator of production expectations. Well-Test Observations With more than 20 drillstem tests performed in the Khuff reservoirs during a 4-year period, the first observation is the wide range of reservoir responses encountered, with an apparent lack of consistency within a given reservoir or field.

Cased-Hole Standalone Evaluation Succeeds in the Absence of Openhole Data

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 202894, “Cased Hole Standalone Evaluation: Breaking the Barrier To Successfully Evaluate Challenging Deep Carbonate Reservoirs,” by Pradeep Menon and Carey Mills, ADNOC, and Suvodip Dasgupta, SPE, Schlumberger, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. Accurate petrophysical evaluations (formation lithology, porosity, and water saturation) are essential in characterizing potential reservoir zones and estimating resources in place. Typically, these evaluations rely on acquisition of openhole logging measurements; however, this is not always possible. The complete paper outlines two examples from tight gas reservoirs in two separate fields offshore Abu Dhabi in which openhole data could not be acquired and petrophysical analysis was undertaken using cased-hole log data. These evaluations successfully identified gas-saturated porous intervals in each well, one of which was successfully flow-tested. Introduction A growing need exists to increase gas production in the UAE. As a result, specific gas-production targets have been mandated from development of currently undeveloped deep gas carbonate reservoirs such as the Permo-Triassic Khuff formation, the middle Jurassic Araej formation, and the Permian Pre-Khuff Unayzah and Berwarth formations. Recent appraisal wells have aimed at evaluating these reservoirs systematically by acquiring a good suite of openhole logs, cutting conventional cores, and conducting well-testing operations. These well data are combined with an evolving regional understanding to better assess and ultimately develop these complex formations. An accurate petrophysical evaluation requires the petrophysicist to develop a realistic evaluation of formation lithology, porosity, and water saturation. These parameters provide the foundations for further work such as static modeling stands, and they must be robust. The Upper Khuff is composed of dolomite occasionally grading to calcareous dolomite with minor interbeds of claystone and anhydrite. In core and cuttings, the dolomite in the uppermost section exhibits a grainstone texture with poor intercrystalline/intergranular porosity. The Lower Khuff is composed of very hard dolomite in part grading to calcareous dolomite, medium-to-dark grey-brown in places, with occasional very-fine-to-medium grainstone texture and very poor intercrystalline porosity. In this paper, the Upper and Lower Araej members are interpreted to have been deposited in an open, marine- circulation shelfal environment, while the Uweinat member is considered to have been deposited in a more- restricted circulation setting with-in a similar shelfal environment. The Barrier Openhole logging generally is the preference for formation evaluation because it represents the simplest environments and benefits from a comprehensive list of available measurements. The variety of tools and diversity of output data available make openhole log acquisition the gold standard for formation evaluation. However, in certain situations in which openhole logging is not possible because of borehole conditions (re-entry of old cased wells, wellbore instability, over-pressure), no option exists other than acquiring petrophysical data in a cased-hole environment.

Testing Tool Conveyed by Coiled Tubing Enables Multiple Tasks in One Run

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199853, “Development and Testing of an Electrical Drillstem Testing Tool Conveyed by Coiled Tubing With a Real-Time Control and Acquisition System,” by Michael Affleck, SPE, Aramco, and Monika Bakke Malmin and Per Egil Almas, Target Intervention, et al., prepared for the 2020 SPE/ICoTA Well Intervention Conference and Exhibition, The Woodlands, Texas, 24-25 March. The paper has not been peer reviewed. Some well-testing operations are executed by performing multiple runs in hole using slickline and coiled tubing (CT). A technology has been developed that combines many of these operations, including contingency stimulation activities, into one run. The complete paper introduces the major system components and reviews challenges associated with design, manufacture, and testing. Developing and Qualification Testing of the Tool Before engaging in the tool- development process, the following major operation-al requirements were identified and confirmed: Reduce the number of different services required and their associated rigup and rigdown times by maximizing the work scope performed with CT Increase timely access to high-quality data for rapid onsite decision making during well testing by converting from memory-based gauges and time-activated downhole shut-in tools to real-time control and data transmission to surface Maximize operational efficiency during well testing by having real-time data transmission to surface Introduce on-demand, selective stimulation capability while the tool and CT remain downhole Allow multiple testing periods during one trip in hole when required at different depths Increase the effectiveness of transferring the well from underbalanced to overbalanced status or vice versa by changing out fluids in the well or pumping nitrogen through the CT Reduce overall risk of stuck pipe or stuck tools during well testing by always having circulation available above the packer module Following multiple design iterations, two complete prototype tools were manufactured and module-level function testing was performed. In parallel, software development and testing of the graphical user interface commenced. Significant effort was applied to ensure that module testing was conducted in realistic downhole scenarios. Dedicated testing equipment was designed and manufactured. Design, manufacture, and module testing was performed in Algard, Norway. Primary components and specifications of the tool are provided in de-tail in the complete paper. Fig. 1 shows the tool [known as the e-drillstem test (e-DST) tool], while Table 1 provides specifications. Following qualification testing but before the first field application, a system-integrity test was performed with the CT service company. Special attention was paid to verifying all interfaces between the downhole tool and the supplier of CT equipment and processes. The verification of operating the new tool through the full length of cable (inside the CT) was tested thoroughly. Significant calibration was expected, required, and performed because the monoconductor cable is used for data communication in addition to tool power supply.

Blasingame decline analysis for variable rate/variable pressure drop: A multiple fractured horizontal well case in shale gas reservoirs

Advanced production decline analysis methods have become more economic and efficient options due to technical and time limitations of well-testing operations in shale gas reservoirs. By normalizing rate with material balance pseudo-time, Blasingame type decline analysis can be applied to variable rate/variable pressure drop system, making the methodology more widely applicable. Blasingame decline analysis of variable rate/variable pressure drop case for multi-fractured horizontal well (MFHW) in shale has been less investigated, because of multi-scale storage spaces and multi-flow mechanisms. This article presents a semi-analytical Blasingame decline analysis model incorporating multi-flow mechanisms with shale's modified material balance pseudo-time. Laplace transformation, point source function, numerical discrete method, perturbation method, and Gaussian elimination method were employed to solve the mathematical problem caused by multi-flow mechanisms. Besides, the material balance pseudo-time was modified by considering adsorption and desorption. In this study, a workflow to investigate the effects of properties of hydraulic fracture (fracture half-length, number of fractures and fracture spacing) and multi-flow mechanisms (diffusion and desorption) on production decline behaviors through diagnostic Blasingame type curves is proposed. The results indicate that productivity is greater with a larger scale of fracture treatment, and better desorption of adsorbed gas is also beneficial to production. The decline rates affected by the fracture treatment scale and supplement capacity show two opposite trends, which is caused by interference between the fractures and boundary, respectively. Except that the data in the diffusion early flow period do not match very well, because the use of diffusion coefficient as a constant, the good fitting results on the whole verifies the model's validity and reliability.

Quantitatively Assessing Hydrate-Blockage Development During Deepwater-Gas-Well Testing

Summary Hydrate-associated problems pose a key concern to the oil and gas industry when moving toward deeper-offshore reservoir development. A better understanding of hydrate-blockage-development behavior can help flow-assurance engineers develop more-economical and environmentally friendly hydrate-management strategies for deepwater operations. In this work, a model is proposed to describe the hydrate-blockage-formation behavior in testing tubing during deepwater-gas-well testing. The reliability of the model is verified with drillstem-testing (DST) data. Case studies are performed with the proposed model. They indicate that hydrates form and deposit on the tubing walls, creating a continuously growing hydrate layer, which narrows the tubing, increases the pressure drop, and finally results in conduit blockage. The hydrate-layer thickness is nonuniform. At some places, the hydrate layer grows more quickly, and this is the high-blockage-risk region (HBRR). The HBRR is not located where the lowest ambient temperature is encountered, but rather at the position where maximum subcooling of the produced gas is presented. As an example case—a deepwater gas well with a water depth of 1565 m and a gas-production rate of 45 × 104 m3/d—the hydrate blockage first forms at the depth of 150 m. In the section with a depth from 50 to 350 m, hydrates deposit more rapidly and this is the HBRR. As the water depth increases and/or the gas-flow rate decreases, the HBRR becomes deeper. Inhibitors can delay the occurrence of hydrate blockage. The hydrate problems can be handled with a smaller amount of inhibitors during deepwater well-testing operations. This work provides new insights for engineers to develop a new-generation flow-assurance technique to handle hydrate-associated problems during deepwater operations.

An experimental study of acidizing operation performances on the wellbore productivity index enhancement

The hydrocarbon fossil fuels are considered as the preferable fuels to provide sufficient energies for industrial purposes. Also, extracting oil from the exploration wells might be a concerning issue in the coming decades, and petroleum engineers push themselves into limits ind novel solutions to enhance the oil recovery factor. Wellbore stimulation procedures exert a profound impact on the current production rate enhancement; respect of the way, reservoir productivity index witnesses a steep rise during the production operation and subsequently would virtually eliminate unnecessary expenditures of other methodologies. Appropriate investigation of acidizing procedures and its significant role in the wellbore production enhancement are utterly dependent on the quality and types of additives, types of acid, acidizing operation and types of formation. The objective of this study is to investigate the effect of injected acid in the carbonated reservoir and subsequently its comparison with the acidizing operations model. Therefore, available well-testing experiments are administered to determine the critical reservoir parameters such as skin factor, reservoir pressure, and permeability. Since then by modeling the wellbore condition in the acidizing operation simulator software, the impact of acidizing on the reservoir is simulated. Consequently, the provided information from software is compared with the real data from well-testing operations. As a result, productivity index is increased dramatically owing to successful acidizing procedures.

An Improved Rate-Transient Analysis Model of Multi-Fractured Horizontal Wells with Non-Uniform Hydraulic Fracture Properties

Although technical advances in hydraulically fracturing and drilling enable commercial production from tight reservoirs, oil/gas recovery remains at a low level. Due to the technical and economic limitations of well-testing operations in tight reservoirs, rate-transient analysis (RTA) has become a more attractive option. However, current RTA models hardly consider the effect of the non-uniform production on rate decline behaviors. In fact, PLT results demonstrate that production profile is non-uniform. To fill this gap, this paper presents an improved RTA model of multi-fractured horizontal wells (MFHWs) to investigate the effects of non-uniform properties of hydraulic fractures (production of fractures, fracture half-length, number of fractures, fracture conductivity, and vertical permeability) on rate transient behaviors through the diagnostic type curves. Results indicate obvious differences on the rate decline curves among the type curves of uniform properties of fractures (UPF) and non-uniform properties of fractures (NPF). The use of dimensionless production integral derivative curve magnifies the differences so that we can diagnose the phenomenon of non-uniform production. Therefore, it’s significant to incorporate the effects of NPF into the RDA models of MFHWs, and the model proposed in this paper enables us to better evaluate well performance based on long-term production data.

Accurate Measurements of Liquid-Condensate Rate With Multiphase-Metering Technology Improve Ecological Impact of Well Test in Deepwater Well Offshore Brazil

Summary Separators have a proven track record and are widely used in well-testing operations. However, their range of applications is relatively narrow, and they can encounter limitations with fluids for which separation quality is an issue. This paper describes a well test in a deepwater well offshore Brazil. To be able to accommodate different production scenarios, two separators and a multiphase meter were used to measure the flow rates. During the test, a comparison of the flow rates from the multiphase flowmeter and those reported by the separator made possible the identification of some carry-over in the separator at a high choke setting. When the choke size was increased, the separator gas rate increased, whereas the liquid rate dropped at the separator, resulting in a very low condensate/gas ratio (CGR). The multiphase meter, on the other hand, reported a constant CGR, allowing for the real-time diagnostic that carry-over was occurring at the separator. At the end of the test, the same increased choke setting was used for a short period of time to confirm the behavior. The same rate results were observed for each phase, and a small amount of liquid could be seen in the gas flare. The final proof came from the analysis of the downhole samples, which confirmed the CGR measured with the multiphase meter. The consistent results from the multiphase meter make the meter ideal to validate the flow-rate measurements from the reservoir and to improve the burning efficiency. By allowing early identification of imperfect separation, the multiphase meter reduces the health, safety, and environmental (HSE) risks associated with well-test operations.

Well-Testing Operations in High-Temperature Environments - Experiences and Best Practices

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148575, ’Challenging Well-Testing Operations in High-Temperature Environments - Worldwide Experiences and Best Practices Learned,’ by Alejandro Salguero, SPE, Edgar Almanza, and Josmar Haddad, SPE, Halliburton, prepared for the 2011 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Muscat, Oman, 24-26 October. The paper has not been peer reviewed. High-temperature (HT) wells are classified as those with bottomhole temperatures in excess of 300°F. New technologies and advances in the industry (e.g., gauges, downhole equipment, and samplers) have been applied to improve decision-making capabilities and to increase well-testing-evaluation success, even in extreme and challenging environments. These enhancements enable improved economics and operational efficiency along with better safety conditions for the involved personnel and lower environmental risk during testing operations. Introduction Well testing is a reliable, dynamic method of retrieving and collecting a variety of information from the reservoir, including permeability, formation damage, bottomhole pressure and temperature, fluid samples, and production quantification. The methods and equipment used to collect these data have evolved as exploration has moved into more-demanding and -challenging environments. In recent years, high-pressure/high-temperature (HP/HT) wells have become more common, and they required new techniques that support the environmental challenges. Proper planning and personnel and qualified equipment are key to achieve successful well-test results, especially considering that well and reservoir conditions can change easily from one region to another, adding challenges to the evaluation operation. HT prospects are defined as wells having bottomhole temperatures in excess of 300°F, and extreme HT wells are prospects having bottomhole temperatures of 350 to 400°F. The chart in Fig. 1 depicts designations for each pressure and temperature definition. Most HT cases have required the use of a deep-well simulator to test and qualify/certify equipment for the expected well-test conditions. The complete paper details three cases of testing wells with temperatures ranging from 340 to 430°F. These cases were carried out in different geographical locations. These wells were chosen because different bottomhole configurations of full-scale downhole assemblies were used. It is important to mention that special tools and equipment are available to perform operations under extreme conditions (e.g., 450°F and 20,000 psi). Currently, electronic memory gauges used in drillstem-test (DST) equipment are designed and tested to work in conditions of 400°F and 30,000 psia. Real-time gauges are available that have been tested to 350°F. However, when more-challenging conditions are encountered, mechanical pressure and temperature gauges must be used.

Well-Testing Operations in High-Temperature Environments - Worldwide Experiences and Best Practices

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper OTC 21060, ’Challenging Well-Testing Operations in High-Temperature Environments - Worldwide Experiences and Best Prac tices Learned,’ by Alejandro Salguero, SPE, Edgar Almanza, and Josmar Haddad, SPE, Halliburton Energy Services, prepared for the 2010 Offshore Technology Conference, Houston, 3-6 May. The paper has not been peer reviewed. Wells with bottomhole temperatures in excess of 300°F are classified as high-temperature (HT) wells. Many offshore developments with these conditions offer large hydrocarbon reservoirs. All, however, have presented significant challenges in terms of operational planning, equipment, engineering design, and job execution with respect to HT-well testing. Different reservoir scenarios required changes in procedures, equipment configuration, and safety requirements. All jobs had to consider environmental criteria in addition to the operator’s testing policies. Introduction Traditionally, well testing is a reliable dynamic method to acquire a variety of information from the reservoir, including permeability, formation damage, bottomhole pressure and temperature, fluid samples, and production quantification. Over time, methods and equipment have evolved, expanding well-test capabilities to different scenarios and adapting to more-demanding environmental and safety constraints. In recent years, high-pressure/high-temperature (HP/HT) wells have become more common. Documented experience in similar cases will be well received because it provides relevant information that will help to make appropriate decisions. With HT wells defined as having bottomhole temperatures in excess of 300°F, extreme-HT wells are defined as wells having bottomhole temperatures between 350°F and 400°F. Background As shown in Fig. 1, many wells around the world with bottomhole temperatures above 300°F have been tested. Tool configuration has changed little because equipment reliability has improved. The lessons learned are extremely valuable for planning and design. Extreme temperatures represent the main challenge for the equipment, particularly for electronics, elastomers, explosives, and some surface equipment, including flexible hoses. In most of these cases, a deep-well simulator was used to test equipment above the expected conditions. Design Consideration Elastomers. The following service conditions must be considered before selecting the proper elastomers. Fluids to be sealed: Consider the type of well fluid, including drilling mud, aggressive brines (such as formiates or calcium bromides), acids, and alcohols. Temperature range: Including minimum and maximum operating conditions along with thermal cycling and potential exclusions. Some seals are not appropriate for low temperatures (i.e., seabed in offshore wells or cold-fluid injection). Pressure range: Maximum and minimum operating range must be considered along with the compression and decompression rate if the pressure is high. Unusual well procedures.

Technology Focus: Production Operations (March 2010)

Technology Focus I was joking with my colleague Todd Zahacy that we should write a series of papers about the number of things we production engineers usually do not know when trying to design or optimize a production system and, therefore, the risks we take that things may not go exactly as planned. Zahacy was quick to forward me a link to the now-famous quote of former US Secretary of Defense Donald Rumsfeld (explaining the limitations of intelligence reports): “There are known knowns. There are things we know we know. We also know there are known unknowns. That is to say, we know there are some things we do not know. But there are also unknown unknowns, the ones we don’t know we don’t know.”* I was thinking mostly of our lack of scientific knowledge in certain areas, but Zahacy reminded me that bad-quality data or bad assumptions also can lead to devastating results. We both believe that engineers should often question the source of information and the validity of assumptions, and then make a conscious effort to think about significant effects that may not have been considered. Some of the papers featured in this issue stress the importance of knowing as much as possible about a production-operation issue before trying to address it: knowing where (and why) the produced fluids or solids are entering the wellbore before planning a workover or knowing how a downhole device is likely to function (or not) under certain operating conditions before installing it in a well, among other issues. Other papers listed here stress the importance of questioning one’s source of information (e.g., the validity of some meters’ readings and/or the representative nature of some fluid samples). Usually, we are good at sharing our successes, but we can also learn much from our failures. Let us share more often the troubles we sometimes get ourselves into, and save our peers in the industry some grief. Production Operations additional reading available at OnePetro: www.onepetro.org OTC 20204 • “The Impact of Reservoir-Fluid Compositional Variation and Valid Sample Acquisition on Flow-Assurance Evaluation” by Oliver C. Mullins, SPE, Schlumberger, et al. IPTC 14068 • “Multiphase Metering in Siberian Gas and Condensate Wells—Lessons Learned in Multiphase Well-Testing Operations Since 2006” by Bertrand Theuveny, SPE, Schlumberger, et al. SPE 123949 • “Case Study: Successful Application of a Novel Conformance Treatment in an Extended-Reach Horizontal Well in the Al Shaheen Field, Offshore Qatar” by M.H. Pedersen, SPE, Maersk Oil Qatar, et al. IPTC 13765 • “Successful Field Application of an Inhibitor-Concentration-Detection System in Optimizing the Kinetic-Hydrate-Inhibitor (KHI) Injection Rates and Reducing the Risks Associated With Hydrate Blockage” by Orlin Lavallie, Dolphin Energy, et al. OTC 20013 • “Operation of Multiphase Flowmeters in the Sour Environment of the Qatif Field, A Case Study” by Faisal M. Al-Dossary, SPE, Saudi Aramco, et al. *www.scientifi camerican.com/article.cfm?id=rumsfelds-wisdom accessed 27 January 2010.

Modeling heat flux calculations in surface well-testing operations

During surface well-testing operations, the produced fluids, either oil or gas, are burnt through oil burners or gas flares, respectively. The heat radiation due to the combustion of these effluent fluids is a critical problem for the personal security and the integrity of the equipment. API-RP-521 gives recommendations according to the heat magnitudes, ranging from 500 Btu/ft 2/h to 5000 Btu/ft 2/h. To ensure safe operations, the heat fluxes must be evaluated and compared to the API recommendations to put in place protective water screens. Despite their influences on the heat distribution, the solid objects in the flame environment, such as tanks or containers are usually not taken into account in the “field” methods currently used. The model presented in this paper is an improved model managing the surrounding objects affecting the heat flux distribution. This model is called a radiosity model, and its formulation is very similar to the one used in global illumination problems. As described in this paper, the field methods tend to underestimate the heat flux in the space in between the flames and the first unoccluded solid bodies. On the contrary, the field methods overestimate the heat flux when there are occlusions between the solid objects in the scene.

Overview: Well Testing (February 2007)

In some of the oil and gas industry's most demanding field developments, engineers can spend months preparing a test program for a deepwater subsea completion that could cost millions of dollars to execute. Other innovative operators are able to convince management of the benefit to drilling horizontal wells to determine pressure profiles through a prolific, yet complicated, reservoir. Conversely, in marginal fields, many wells may not have been tested for years and may never be tested before they are disposed of in the next asset sale. Clearly, opportunity, mitigating risk in frontier areas, lack of technical resources, and other justifications play a role in the frequency and type of well-testing operations that an engineer will recommend. In my own experience, it can be difficult to convince operations personnel that a good testing program can increase production by identifying underperforming wells for remedial programs or more nearly optimum operating practices. Our role as engineers is to use our education, judgment, and experience to make decisions that provide the highest-value information at the lowest possible cost to our project. The SPE technical-paper library provides a great resource of where this has been done by some of our industry's top technical people. The papers reviewed for this month's well-testing feature were some of the most interesting and varied in the time I have been on the JPT Editorial Committee. There were many more technical papers I could have chosen this year that offer real applicability to the practicing field engineer and just as many that would interest those doing research. The papers that were selected represent progress in areas of well-test interpretation that have been problematic in the past. There also are reviews of advanced well-test-interpretation methods that should be a great resource to many. Also discussed are new ways of applying well-development technology to answer questions about optimizing an entire field's development plan. I would encourage anyone with the slightest interest in well testing to do a thorough literature search to take advantage of the many well-written papers on a broad variety of well-testing topics that have been published this year. Even in our robust and high-oil-price environment, we find persistent pressure to do more with less. I found the technical papers reviewed this year to be of very practical interest to the well-test designer and interpreter interested in maximizing the information that can be extracted from well testing. Good reading. Well Testing additional reading available at the SPE eLibrary: www.spe.org SPE 103222 "Rate Allocation Using Permanent Downhole Pressures" by M. McCracken, SPE, ExxonMobil Upstream Research, et al. SPE 103040 "A Digital Pressure-Derivative Technique for Pressure Transient Well Testing and Reservoir Characterization" by A.F. Veneruso, SPE, Schlumberger, et al. SPE 102079 "From Straight Lines to Deconvolution: The Evolution of the State of the Art in Well-Test Analysis" by A.C. Gringarten, SPE, Imperial College, London.

Application of Water Injection/Falloff Tests for Reservoir Appraisal: New Analytical Solution Method for Two-Phase Variable Rate Problems

SummaryThe challenges of reducing or eliminating emissions associated with well-testing operations during reservoir appraisal have revived interest in water injection/falloff tests. However, the two-phase flow and injection-induced temperature changes associated with injection/falloff tests complicate the problem of well-test analysis. Strictly speaking, these effects make the pressure transient problem nonlinear and preclude using conventional superposition technique to construct solutions for variable rate problems.In this paper, we present a new analytical method for accurate solution of the pressure transient problem for two-phase flow associated with water injection/falloff tests. The solution algorithm allows one to compute the solution for any stepwise constant rate sequence that includes multiple injection and falloff periods. The method is general, and can be used for water injection governed by any physically meaningful relative permeabilities, as well as for pistonlike displacement.

Multiphase Flow Metering: Current Trends and Future Developments

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract Over the last decade, the development, evaluation, and use of multiphase-flow-metering (MFM) systems have been a major focus for the oil and gas industry worldwide. Many alternative metering systems have been developed, but none can be referred to as generally applicable or universally accurate. Both established and novel technologies suitable to measure the flow rates of gas, oil, and water in three-phase flow are reviewed and assessed within this framework. Technologies already implemented in various commercial meters then are evaluated in terms of operational and economical advantages or shortcomings from an operator's point of view. The lessons learned about the practical reliability, accuracy, and use of available technology are discussed. As operators now realize, use of MFM systems (MFMSs) is essential in exploiting marginal fields. A new approach to flow assurance, deepwater developments, downhole/seabed separation systems, and wet-gas fields is foreseen. The authors suggest where additional research to develop the next generation MFM devices will be focused to meet the as yet unsolved problems. Brief History The first commercial MFMSs appeared approximately 10 years ago, as a result of several multiphase metering research projects in the early 1980s. The driving force to develop MFM technology was the forecast decline of production from the major North Sea fields, accompanied by the necessity to tie backfuture smaller discoveries to existing infrastructure. Increasing gas and waterfractions, inherent in a mature producing province, would create more-unstable flow conditions in existing production facilities and require more-flexible multiphase solutions. In less than a decade, MFM has become accepted in the field and is beginning to be considered as a primary metering solution for new field developments. MFM Applications Within the oil and gas industry, it is generally recognized that MFM could lead to great benefits in terms of the following.1,2,3 Layout of Production Facilities. The use of MFMs reduces the hardware needed for onshore, offshore topside, and offshore subsea applications. Of primary importance is the removal of a dedicated test separator for well-testing applications. Use of MFM (with its smaller footprint) for topside applications minimizes platform space and load requirements for well-testing operations. Finally, costly well-testing lines can be stripped from the production facilities, which may be of vital importance for unmanned locations, deepwater developments, and satellite fields. Well Testing. Conventional test separators are expensive and require much time to monitor each well's performance because of the time required to reach stabilized flow conditions. It is particularly important in deepwater developments, because of the exceptional length of the flowlines. In such cases, production from individual wells connected to the same manifold may be monitored by use of a dedicated test line to avoid shutting down all the wells, then testing them one by one (with considerable production loss). However, the expense of a separate flowline may be prohibitive, hence the advantages of MFM installed in the subsea manifold. Test separators have an accuracy between approximately 5 and10% (currently achievable with MFMSs) but require regular intervention by trained personnel and cannot provide continuous well monitoring. Another disadvantage of conventional well testing with conventional separators is that well performance suffers after shutdown cycles related to well testing. Often, wells tested on a regular basis require more-frequent workovers to maintain their production rates. Use of MFMSs for exploration-well testing4 provides satisfactory flow measurements without separation of the phases. It is claimed that they can be used to monitor the well during its cleanup flow (traditionally, this flow information is lost because the well stream is not directed through the test separator). Added value is represented by improved control of the drawdown applied to the formation, the pressure transient, and shortened flow periods. Reservoir Management. MFMSs provide real-time, continuous data to enable operators to characterize field and reservoir performance better and react faster. Changes in gas/oil ratio or water cut can be detected and quantified immediately, where as traditional test separators provide information about only cumulative volumes at discrete points in time.

Using Downhole Pressure Gauges in Hostile Deep Wells, Villafortuna-Trecate Field

This paper summarizes extensive, pioneering experience with the first 5-year well-testing project in the hostile ultradeep wells of the Villafortuna-Trecate field. Performance of the various downhole high-temperature, high-pressure (HTHP) gauges used is investigated, and the relevant technology is compared throughout the field history. Awareness of the quality of data acquired and the role played by redundancy (use of more gauges simultaneously) are identified as key points in planning successful future HTHP operations.

High-Pressure Well Design

Summary Shell U.K. E&P (Shell Expro), operator in the U.K. North Sea on behalf of Shell and Esso, plans to drill 20 high-pressure wells during the next 2 years. The well design is based on new standards developed after the U.K. Dept. of Energy restriction on high-pressure drilling in the autumn of 1988. Studies were carried out to optimize casing design and drilling performance on these wells. Several casing schemes, including a slim-hole option, were analyzed. The material specifications for casing and drillpipe were reviewed to ensure that they met the loads imposed during drilling, well-control, and well-testing operations. The requirement for sour-service material was weighted against possible H2S adsorption by the mud film. As a result, a new drillstring and two high-pressure casing schemes have been specified. The high-pressure casing scheme used depends on the maximum expected surface pressure.

WIRELINE FORMATION-TESTER PERFORMANCE ON THE NORTH WEST SHELF

The formation-interval-tester was introduced to the North West Shelf in December, 1970 Originally it was used as a first-look test method, with drill stem testing retained as the standard evaluation technique in all potential reservoir sections. Systematic use of this technique in parallel with drill-stem testing has allowed the accumulation of a significant volume of comparative data. This has provided a unique opportunity to examine the validity of wireline-testing as an alternative to the more traditional method of reservoir evaluation.The wireline-tester has been found to be a reliable indicator of movable hydrocarbons in reservoir rock, after experience allowed the development of regional interpretation limits. Such variables as gas:oil ratios and oil gravities are determined within acceptable limits of accuracy. Formation pressure determinations are consistent' and are thought to be more reliable than those derived from drill-stem-testing. With the data available it is normally possible to calculate the indicated formation permeability. This however being a single point determination the result is of questionable value. Experience has shown that "order of magnitude" agreement is normally achieved between wireline-tester permeabilities and those determined from drill-stem-testing in the same interval.The reduction in cost resulting from the application of this technique is particularly significant. Savings may be related directly to the relative reduction in rig time required by this operation compared with that required for drill-stem-testing. As the cost of offshore operations increases rapidly the resultant savings will grow in significance.Also of concern in all well-testing operations is the risk to which the rig and personnel are subjected. On floating offshore rigs the flowing well condition required by drill-stem-testing requires the acceptance of certain associated risks. Wireline testing is by comparison a risk-free operation.The recognition of the inherent limits of this approach to well testing is important if satisfactory results are to be achieved. Where the required reservoir parameters are those that can be satisfactorily determined with the wireline tester it offers a real alternative to the more traditional evaluation techniques.