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Drillstem Testing
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215454, “Enhancing Well-Control Safety With Dynamic Well-Control Cloud Solutions: Case Studies of Successful Deep Transient Tests in Southeast Asia,” by M. Ashraf Abu Talib, SPE, M. Shahril Ahmad Kassim, and Izral Izarruddin Marzuki, SPE, Petronas, et al. The paper has not been peer reviewed. _ The complete paper addresses challenges related to well control and highlights the successful implementation of deep transient tests (DTT) in an offshore well performed with the help of a dynamic well-control simulation platform. The paper aims to provide insights into the prejob simulation process, which ensured a safer operation from a well-control perspective. Additionally, a comparison between simulated and actual sensor measurements during the DTT operation is presented. DTT DTT is a formation-testing (FT) method that allows pressure transient tests that reach deeper into the formation compared with conventional interval pressure transient tests (IPTT). DTT enables the testing of formations with higher permeability, greater thickness, and lower viscosity and real-time measurement of crucial parameters. During a DTT, formation fluid is pumped from the reservoir; upon stopping the pump, the formation pressure begins to recover as fluid further from the wellbore replaces the extracted fluid. By analyzing the resulting pressure transient, properties such as formation permeability, permeability anisotropy, and other characteristics can be determined. DTT allows for a better understanding of reservoir characteristics and rock heterogeneity. When properly designed and executed, DTT can reveal potential baffles and boundaries within the radius of investigation. A further advantage of DTT over drillstem tests (DST) is its minimal fluid flow, which allows for the attainment of objectives while contributing to the United Nations sustainable development goals. In DTT operations, the FT tool is connected to the drillpipe through a circulating sub and a slip joint. The circulating sub plays a critical role in DTT operations because it enables the continuous mixing of pumped formation fluid with circulated mud and facilitates its transportation to the surface (Fig. 1). Typically, a constant circulation rate ranging from 100 to 250 gal/min is maintained. During circulation, the annular preventer is closed and the mud/hydrocarbon mixture is directed through the choke line to the mud/gas separator (MGS) once it reaches the surface. No formation fluids are flared during DTT operations. Instead, the circulated oil is retained in the mud and only small amounts of gas are vented. By use of a slip joint, the FT remains anchored to the borehole wall. A high-resolution pressure gauge is used to capture and interpret even minor pressure fluctuations during the pressure transient buildup.
_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216673, “CO2 Injectivity Test Proves the Concept of CCUS Field Development,” by Yermek Kaipov, SPE, and Bertrand Theuveny, SLB, and Ajay Maurya, Saudi Aramco, et al. The paper has not been peer reviewed. _ The complete paper presents a unique case study on injectivity tests done in Saudi Arabia to prove the concept of carbon capture, use, and storage (CCUS) capability. It describes the design of surface and downhole testing systems, lessons learned, and recommendations. The injectivity tests were effective in identifying and confirming the best reservoir for CO2 injection and defining the best completion strategy. Creating injection conditions close to CCUS is vital, especially in heterogeneous carbonate reservoirs where the petrophysical correlations for the reservoir model require calibration with dynamic data. Introduction The energy company has conducted an extensive evaluation campaign by drilling appraisal wells through multizone saline aquifer reservoirs on different sites close to potential sources of CO2 at the surface. The evaluation program included coring, openhole logging, formation testing for stress-test and water sampling, and injectivity testing in the cased hole. Apart from reservoir characterization, different completion strategies were evaluated by performing injectivity tests in both vertical and horizontal wells. The lower completion was represented by perforated casing and an open hole. Injectivity Testing Injection tests are a commonly used method in waterflood projects to evaluate the injectivity capacity of the well and reservoir. The test involves an injection period with one or more injection rates, followed by a falloff period (Fig. 1). During the injection period, the liquid is injected at a stable rate to reduce the risk of near-wellbore formation damage caused by fluid incompatibility or exceeding the fracture gradient and inducing formation fracturing. The bottomhole-pressure data acquired during the test is analyzed using the pressure transient analysis method to estimate the permeability thickness, skin factor, and lateral heterogeneities. Additionally, the injection logging profile can be conducted along the sandface to assess completion efficiency and formation heterogeneity. By interpreting the results of the injection test, engineers can optimize the injection rate and improve the performance of the well and reservoir, ultimately leading to more-efficient oil recovery. Injectivity Test: Case Study The injectivity tests were conducted on virgin reservoirs using vertical appraisal wells that were sidetracked horizontally into the reservoirs with the greatest potential for storage. The reservoirs’ depths varied from 4,000 to 8,000 ft, with a normal gradient of reservoir pressure and temperature. The injectivity test design used reservoir properties estimated from the openhole evaluation, such as porosity, permeability, reservoir pressure, temperature, reservoir fluid sample, and fracture gradient. These data were used to set injectivity-test objectives, calculate expected well parameters, select equipment, and plan operations. The primary goal of the tests was to assess reservoir injectivity by injecting water, nitrogen, and CO2 to prove the concept for a CO2-injection project. While water and nitrogen injections are well-known in the industry, the CO2 injectivity test was new and required more attention during the design phase to evaluate all possible risks.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.55)
Standing alone as the shortest month of the year, February also features JPT’s Well Testing Technology Focus, reviewing the latest industry publications on the subject. Well testing has enjoyed a recent uptick in activity and interest as operators continually realize the value in understanding and monitoring the dynamic performance of their reservoirs. Whether it pertains to the deliverability of conventional oil and gas or the storage potential for carbon capture and storage, large-scale dynamic data remains one of the more coveted pieces to the subsurface puzzle. There is no silver bullet for reservoir characterization. Instead, proper characterization will always be the result of integrating static and dynamic data, collected at varying scales, with a macro geological understanding. Technology facilitates the collection of the aforementioned data. With the latest technologies pushing limits of what can be achieved, subsurface engineers must rigorously evaluate what reservoir characterization techniques and tools are suited for project objectives. Formation testing (FT) platforms provide many options for operators to get a first look at dynamic reservoir performance and nearly always precede a well test. After digesting the alphabet soup of acronyms, so many FT options exist that one may encounter what psychologists refer to as “choice overload.” FT objectives also may begin to overlap with objectives traditionally reserved for drillstem tests (DSTs), narrowing a long-standing technology gap. The current advances in FT tools are exciting, and using FT tools to perform a “mini-DST” makes for brilliant marketing. However, “mini” could mean up to 10,000 times less produced volume, which undoubtedly affects objectives thought to overlap. Subsurface complexity is mitigated by defining clear objectives and executing data-collection programs to reduce uncertainty. Caution should be taken in selecting how to dynamically test your reservoirs. Regardless of how advanced hardware becomes, achievable objectives always will be dependent on key factors such as rock and fluid properties, reservoir geometry, and local regulatory and environmental considerations. This month’s papers highlight ongoing developments from different segments of the well-testing discipline. Dive into valuable lessons learned from a frontier carbon capture, use, and storage project, backed by an impressively sized data set and an in‑depth review of multiphase effects. This case study covers differing saturations around the wellbore region and fluid types in operations and should have global applications. Learn about the limitations and potential pitfalls of nonisothermal effects in pressure transient analysis, which pose challenges in the reservoir characterization of geothermal wells. Sensitivities to thermal effects on reservoir rock properties provide intriguing insights. Completion efficiency also may be affected by thermal effects, resulting in additional pressure drop at sandface. Finally, catch up on one of the weapons most recently added to the well-testing arsenal with powerful new FT tools that feature industry improvements for greater flexibility and improved data reliability. Recommended additional reading at OnePetro: www.onepetro.org. OTC 32610 Multiphase Flowmeter Comparison in a Complex Field by Mohammed Alqahtani, Saudi Aramco, et al. IPTC 23050 Frequently Asked Questions in the Interval Pressure Transient Test and What Is Next With Deep Transient Test by Saifon Daungkaew, SLB, et al.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.56)
Standing alone as the shortest month of the year, February also features JPT's Well Testing Technology Focus, reviewing the latest industry publications on the subject. Well testing has enjoyed a recent uptick in activity and interest as operators continually realize the value in understanding and monitoring the dynamic performance of their reservoirs. Whether it pertains to the deliverability of conventional oil and gas or the storage potential for carbon capture and storage, large-scale dynamic data remains one of the more coveted pieces to the subsurface puzzle. There is no silver bullet for reservoir characterization. Instead, proper characterization will always be the result of integrating static and dynamic data, collected at varying scales, with a macro geological understanding.
Jeffrey Gagnon, SPE, is a subject-matter expert of transient well testing at ExxonMobil. He and his team oversee ExxonMobil’s worldwide exploration and appraisal testing (including design and planning, onsite operations supervision, and data interpretation and integration) while supporting pressure transient analysis for producing assets. Gagnon has co-authored SPE manuscripts regarding reservoir characterization and simulation. He holds MS and ME degrees in petroleum engineering from Robert Gordon University and Texas A&M University, respectively, and an undergraduate degree in civil engineering from the University of New Hampshire. Gagnon is a member of the JPT Editorial Review Board and can be reached at jeffrey.gagnon@exxonmobil.com.
- North America > United States > Texas (0.33)
- North America > United States > New Hampshire (0.33)
This course teaches the systematic analysis and design procedures for testing pressure buildup and flow tests. Example applications focus on identifying the appropriate reservoir model, estimating effective formation permeability, and quantifying damage or stimulation. This course will provide you with an understanding of the fundamentals of buildup and flow test analysis--an understanding that will provide insight into the strengths and limitations of the methodology used in modern commercial pressure-transient test analysis software. This is a basic course in well test analysis and design, suitable for engineers and physical scientists who have little if any background in well test theory or practice. It focuses on applications rather than theory.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
The CO2 Storage Resources Management System (SRMS) provides a classification and categorization system that reflects geologic certainty and project maturity of storable quantities. This short course explains the classes used to indicate the level of project maturity, which is indicative of data available for the assessment. The Storage Capacity indicates the highest level of project maturity, while Prospective Storage Resources is the class for undiscovered storage resources, with the lowest level of project maturity. The categories indicate geologic certainty, e.g. The course includes discussions of commercial evaluation of storage projects and estimating CO2 storable quantities, with examples.
- North America > United States > Colorado (0.30)
- North America > United States > New Mexico (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Education (1.00)
- Government > Regional Government > North America Government > United States Government (0.51)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
Sour-Rated 10,000-psi System High-Temperature Gas Development Wells: Sustaining the Malaysian National Gas Supply Through a Journey of Optimization in North Malay Basin
Jong, Siaw Chuan (Hess Exploration and Production Malaysia B.V. (Corresponding author)) | Aziz, Khairil Faiz Abdul (Hess Exploration and Production Malaysia B.V.) | Goo, Jia Jun (Hess Exploration and Production Malaysia B.V.) | Hiew, Ronnie (Hess Exploration and Production Malaysia B.V.) | Strickland, Kenny (Hess Exploration and Production Malaysia B.V.) | Hussin, Arief (Hess Exploration and Production Malaysia B.V.) | Yusof, Khazimad (Hess Exploration and Production Malaysia B.V.) | Macleod, Andy (Hess Exploration and Production Malaysia B.V.) | Yusoff, Syukur (Hess Exploration and Production Malaysia B.V.) | Chung, Chay Yoeng (Hess Exploration and Production Malaysia B.V.) | Liew, Alex (Hess Exploration and Production Malaysia B.V.)
Summary High temperature (HT), high carbon dioxide (CO2) coupled with hydrogen sulfide (H2S) contents, and rapid pore pressure fracture gradient (PPFG) pressure ramp increase in gas development wells can lead to significant capital expenditures for operators. Such wells typically need high corrosion resistance alloy material with at least a 10,000-psi (10-ksi)-rated system to complete. The deep reservoirs of the North Malay Basin, offshore peninsular Malaysia, also fall into the described category. In this paper, we aim to share the optimization journey, applications, and learnings of the company’s HT sour-rated 10-ksi gas development wells through several phases, besides fulfilling the gas delivery need for the country. In addition, we identify engineering and operational optimizations to reduce the well’s time and cost while upholding the safety of the crew as a top priority. The sour-rated HT gas development campaign for the company began in the year 2017, followed by a second campaign in the year 2018. Our focus centers on the third campaign, which concluded in the year 2022. A total of four, three, and four wells were drilled and completed in the first, second, and third campaigns respectively. The company’s wells engineering team applied Lean methodologies that covered the entire Plan-Do-Check-Adjust cycle to achieve optimization. Using well data, learning from experiences, working together, maintaining consistency, and pursuing ongoing enhancements are the main factors that ensure positive optimization outcomes. Fit-for-purpose drilling and completions equipment design and application, rig offline capabilities planning, wellhead dummy hanger plug design for offline cementing, intervention-less production packer setting device, offline annulus nitrogen cushion fluids displacement, and other applications will be explained in the paper. In this paper, we describe the operational challenges faced and outline the applied optimizations that led to significant improvements in the well performance compared with targets and previous campaigns. The optimization efforts by the wells team extended from the engineering phase to the execution stage, including the use of in-house digital capabilities to monitor well performance, in alignment with industry practice. The recent campaign post-optimization concluded with no safety incidents, average per well more than 48 days ahead with 39% lower cost than previous campaigns, average of 5.6% overall well nonproductive time (NPT), and achieved first gas to meet the country’s power generation demand. Furthermore, the motivating optimization results also coupled with 25% more production results compared with the prognosed. The positive results of this optimization journey were significantly influenced by transparent, collaborative, and proactive communication across different departments.
- Asia > Malaysia > South China Sea (0.61)
- Asia > Malaysia > Kelantan > South China Sea > Gulf of Thailand (0.61)
- Energy > Oil & Gas > Upstream (0.93)
- Education > Educational Setting > Online (0.72)
- Education > Educational Technology > Educational Software > Computer Based Training (0.43)
Two common goals of Rate Transient Analysis (RTA) are the quantification of early time well performance using the Linear Flow Parameter (LFP), as well as the contacted pore volume being drained (e.g. These two parameters are essential for understanding the effects of completions, geology, and depletion which then advises different strategies for optimizing the economics of future development. We'll cover the following topics in the course: This course outlines limitations in traditional RTA analysis, and goes through three new technologies that has been introduced the past few years to help enhance our understanding of tight unconventionals, namely (1) Numerical RTA (2) multiphase flowing material balance (FMB) and (3) Fractional RTA. Petroleum engineers, managers and geoscientists who would like to learn RTA in a practical and hands-on way. All cancellations must be received no later than 14 days prior to the course start date.