Results
Abstract Smart Liners rely on the limited-entry principle where a number of small holes act to distribute acid along the un-cemented reservoir section. Over the past two years, this technique has become a key method for matrix-acid stimulation of ADNOC's carbonate reservoirs. The objective of this paper is to summarize the learnings from more than 100 deployments and tie together the key elements of the hole spacing design, the stimulation job execution, and the performance monitoring. A software algorithm generates the hole spacing design to honor a predefined acid flow distribution along the drain length. Quantification of the stimulation efficiency is addressed in several ways. First, the baseline well performance is established with production tests covering several months and in some cases accompanied by a pre-stimulation production logging test (PLT). The stimulation job is then analyzed and compared against a wormhole model to derive the transient injectivity improvement versus acid volume pumped. After the stimulation, the stabilized performance is analyzed in terms of production testing and occasionally a pressure buildup survey and a PLT. Results have so far been very encouraging. Smart Liners have been deployed predominantly in oil producers and water injectors but a few implementations have targeted tight gas reservoirs. A typical steady-state productivity gain is 100-150% above the baseline unstimulated well and the technique consistently outperforms conventional matrix-acid stimulation techniques. The post-stimulation PLT's show that the entire wellbore contributes to flow, even in extended-reach wells. The majority of the efficiency improvement seems to occur with an acid coverage of 0.5 bbl/ft but some wells benefit from higher acid dosages. A wormhole model developed specifically for this completion-stimulation method can reproduce the observations and helps guide designs of future stimula0tion jobs by suggesting modifications to the hole spacing, which will improve the performance improvement using less acid volume.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.21)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Chalk Formation (0.99)
- Asia > Middle East > Turkey > Selmo Field (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > Al Shaheen Field > Shuaiba Formation (0.99)
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Hydro-Geomechanical Observations During Multistage Hydraulic Stimulation at the Bedretto Underground Laboratory, Switzerland
Bröker, K. (ETH Zurich, Institute of Geophysics) | Ma, X. (ETH Zurich, Institute of Geophysics) | Gholizadeh Doonechaly, N. (ETH Zurich, Institute of Geophysics) | Hertrich, M. (ETH Zurich, Institute of Geophysics) | Hansruedi, M. (ETH Zurich, Institute of Geophysics) | Giardini, D. (ETH Zurich, Institute of Geophysics) | _, _ (Bedretto Lab Team) | Rinaldi, A. P. (Swiss Seismological Service) | Clasen Repollés, V. (Swiss Seismological Service) | Obermann, A. (Swiss Seismological Service) | Wiemer, S. (Swiss Seismological Service)
ABSTRACT A series of hydraulic stimulation experiments were performed in the Bedretto Underground Laboratory for Geosciences and Geoenergies in Switzerland to answer questions about the creation of an engineered geothermal reservoir in crystalline rocks. A 400 m long stimulation borehole was divided into 15 intervals by a multi-packer system. In this work, we present preliminary results of interval 8 in which two injection phases were performed with a 3.5 months gap in between. The two phases differ in the injected volume and injection protocol (pressure vs. flow rate controlled). Within the interval, we mapped a cluster of sub-parallel pre-existing open fractures that are reasonably well oriented for reactivation in the estimated stress field. The interval pressure and flow rate data from the injections reveal a reactivation of the pre-existing fractures, associated with a large increase in injectivity. A comparison of the expected stress field around the stimulation interval with the observed reactivation pressure indicates that the fractures were likely reactivated by hydraulic shearing. The reactivation is also supported by other data sets from the extensive monitoring network, e.g. distributed temperature and strain sensing. INTRODUCTION Engineered geothermal systems (EGS) have received increasing interest in recent years because they are considered a low emission, renewable energy source (Lu, 2018; Aghahosseini and Breyer, 2020). An EGS aims to extract geothermal energy from crystalline basement rocks with low permeability. The permeability is enhanced either by hydraulic shearing of natural fractures or shear zones, or by hydraulic fracturing of intact rock, or by a mixture of both (McClure and Horne, 2014). This permeability enhancement is often linked to induced seismicity, which can reach damaging levels if large fault zones are reactivated (e.g. Deichmann and Giardini, 2009; Evans et al., 2012; Ellsworth et al., 2019). To address this challenge, several scaled-down in situ hydraulic stimulation experiments have been conducted in underground research laboratories in representative crystalline rock types (e.g. Amann et al., 2018; Zimmermann et al., 2019; Schoenball et al., 2020; Fu et al., 2021).
- Europe > Switzerland (1.00)
- North America > United States (0.95)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.68)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- (2 more...)
Summary The loss of well integrity in oil and gas and CO2 injection wells provokes leaks that potentially pollute underground water reservoirs and the surrounding environment. The present publication reviews the existing literature investigating the loss of well integrity due to damage development in the cement sheath, focusing on qualitative and mainly quantitative information regarding cracks, effective permeability, and leak flows. Methods applied for leak detection on-site are reviewed, and the difficulties of these methods in providing quantitative results are highlighted. The outputs of laboratory experiments and computer simulations, considered essential to complement on-site measurements, are also reported. The review of the existing literature shows that for most of the damaged cement sheaths the observed crack widths range between 1 and 500 µm, the permeability ranges from 10 to 10 m, and the leak rates range between 10 and 10 000 mL/min for gas leaks and between 1 and 1000 mL/min for oil leaks.
- South America (1.00)
- North America > United States > Texas (1.00)
- Asia > Middle East (1.00)
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- Research Report > New Finding (0.67)
- Overview (0.67)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (11 more...)
Downhole Water Sink at High Mobility Ratio: The Tambaredjo Field Pilot Test
Niz-Velasquez, E. (Dunia Technology Solutions, Paramaribo, Suriname) | Nagesar, H. S. (Staatsolie Maatschappij N.V., Paramaribo, Suriname) | Bhajan, R. V. (Staatsolie Maatschappij N.V., Paramaribo, Suriname) | Nandlal, B. (Staatsolie Maatschappij N.V., Paramaribo, Suriname)
Abstract This study discusses the development and results of the Downhole Water Sink (DWS) pilot test in two wells of the Tambaredjo Field (Suriname). It includes the mechanical completion, design and execution of operating strategy, well performance and forecast, and reservoir simulation employing an oil-in-water emulsion formulation. The DWS process, well and reservoir information and properties are introduced. The problem of heavy oil production in oil-water contact (OWC) areas is explained. The results in terms of production data and its analysis, and issues encountered, are presented. A reservoir simulation model capable to handle transport of oil components in water phase is described and used to history-match the production performance. Then, conclusions are drawn from the information presented. Although the water sink is expected to work under stable displacement conditions, the results of the pilot test show that DWS could successfully reduce water coning at the prevalent unstable mobility ratio. It also promoted inverted coning of oil from the transition zone to the water leg completion. This was confirmed by direct measurements of oil content in the fluid produced from the water leg completion. The physical mechanism that allows such phenomenon is hypothesized to be the flow of oil droplets of size smaller than that of the typical pore throat. Such mechanism was numerically modeled and found to be consistent with the pressure and rate measurements at both wells. Early measurement and completion issues in the first well were overcome later on and in the second well. This paper presents the first results for DWS in a heavy oil reservoir with highly adverse mobility ratio. The results will serve as a guidance for implementation of DWS in heavy oil reservoirs overlying an oil-water contact.
- North America > United States (1.00)
- South America > Suriname > North Atlantic Ocean (0.61)
- South America > Guyana > North Atlantic Ocean (0.61)
- Europe > United Kingdom > North Sea > Central North Sea (0.40)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.97)
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.97)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (6 more...)
Cement Placement Modeling—A Review
Bois, A.-P. (CURISTEC (Corresponding author)) | Zhao, H. (China Oilfield Services Limited) | Wen, D. (China Oilfield Services Limited) | Luo, Y. (China Oilfield Services Limited) | Li, Y. (China Oilfield Services Limited) | Badalamenti, A. M. (CURISTEC) | Song, M. (China Oilfield Services Limited) | Calvo, C. (CURISIT) | Reñe, J. (CURISIT) | Liang, H. (CURISTEC)
Summary Ensuring cement sheath placement is of paramount importance for the success of a primary cementing operation. Poor mud displacement and fluid contamination can lead to cement isolation failure, loss of production, and even well abandonment. Over time, many cement placement computerized models have been developed, leading to a significant number of theoretical and case history papers. However, using these to design a cement job is difficult because their physical and mathematical assumptions are most of the time unclear, and because their application requires balancing precision with computation time. Models that are too precise may lead to very long runs, while oversimplified models could result in nonpredictive simulations. To the authors' knowledge, nothing has been published to explain how to perform efficient predictions with a cement placement computerized model. Such is the object of this paper. It presents an extensive analysis of all the available cement placement computerized models, highlighting their advantages and disadvantages and listing their assumptions. This analysis indicates that (1) the actual methods used to estimate the equivalent circulating density window are not rigorous enough; (2) there still exist a lot of uncertainties when predicting the tubular standoff; (3) modeling fluid contamination, especially when the fluids are not compatible, remains very cumbersome, if not impossible, because the true interfaces' physics is not completely considered; (4) a local contamination observed at an intermediate time can disappear at the end of the simulation due to numerical diffusion, meaning that just looking at the concentration maps at the end of placement is not sufficient to judge the efficiency of a displacement scenario; and (5) changes in geometries along the cement sheath are not considered with precision. This work allows establishing guidelines to help understanding how to manage simulation inputs and analyzing and communicating the produced results. Introduction Ensuring a good cement sheath placement is of paramount importance for the success of a primary cementing operation. Poor mud displacement and fluid contamination can lead to cement barrier isolation failure, loss of production, and even well abandonment. Over time, many cement placement computerized models have been developed, which has resulted in many papers being published, either on the underlying theories or on their use. However, nothing has been published to explain how to use them to make efficient predictions. Such is the objective of this paper.
- Europe (1.00)
- Asia (0.67)
- North America > United States > Louisiana (0.46)
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- North America > United States > Mississippi > Improve Field (0.99)
- North America > United States > Louisiana > China Field (0.99)
Abstract In this paper, we propose a Control Volume Material Balance (CVMB) approach for proxy reservoir simulation and apply it to real-time flow diagnostics. Instead of utilizing a comprehensive reservoir simulator, it estimates the saturations distributions by mapping the mass difference between injected and produced fluids recorded at wells into 3D grid blocks. On this basis, we perform real-time flow diagnostics to evaluate the dynamic heterogeneity of the instantaneous displacement flow field which can be used for making effective and opportune decisions to improve oil recovery. CVMB solves the pressure and flow fields implicitly, and the transport equations explicitly. It incorporates 3D heterogenous rock properties. The fundamental idea of the CVMB method is to divide the 3D flow field into a series of 1D well-pair Control Volumes (CVs). A well-pair Control Volume is composed of grid blocks in the intersection of the sweep and drainage regions of the injector and producer. The fluid flow in and out of the 1D CV can only occur at the wells, and the in-situ fluid volumes are determined by the well flow rates and the well allocation factors. In each CV, we assume the displacement in the grid blocks is piston-like and follows the 1D order of ascending forward time-of-flight. The fluid saturation distributions are determined by defining the cut-off time-of-flight for the displacement front. We show how the CVMB method improves the pattern-based mass balance approaches in the following aspects: 1) enables real-time flow diagnostics in terms of the hydrocarbon dynamic Lorenz coefficient without a comprehensive reservoir simulator; 2) enhances the simplicity and extensibility of the pattern-based mass balance approach without mapping between grid blocks and streamlines; 3) reduces the smearing effects in conventional mass balance approach by defining 1D CVs using forward time-of-flight. The proposed CVMB method utilizes the historical well flow rates as the input to estimate the swept regions and its average saturation with remarkable efficiency and sufficient accuracy for real-time flow diagnostics.
- North America > United States > Texas (0.28)
- Europe > Austria (0.28)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (2 more...)
Abstract Most horizontal oil wells will after a time start producing unwanted fluids. Autonomous Inflow Control Valves (AICV) may help to choke these unwanted fluids and consequently improve the carbon efficiency. This paper publishes new experimental data describing how an AICV handles a medium-light oil (6 centipoise), water and gas at full reservoir conditions. A further objective is to evaluate how the AICV might impact well performance under various conditions. To verify the single and multi-phase flow behaviour of the AICV for medium-light oil viscosity, an extensive multi-phase flow loop campaign was performed. The test was performed under real reservoir conditions, i.e., with formation water, reservoir oil and hydrocarbon gas at the given reservoir temperature and pressure. Preceding the external and independent verification, internal laboratory studies were performed with model fluids. A simple conceptual reservoir model with realistic boundary conditions was built to explore and understand the impact of this AICV for various reservoir scenarios. At various differential pressures the single-phase oil, water, and gas rates were measured. Performance at varying water and gas fractions were measured to get improved understanding and knowledge of multi-phase flow occurring in a well. The results show clearly that the AICV will choke gas and water effectively, both at single and multi-phase flow conditions. The external and independent verification are consistent with the internal laboratory evaluations with model fluids. The AICV shows roughly a linear transition from 100% oil to 100% gas performance, and similar for 100% oil to 100% water, implying that the AICV will always prioritize sections with the largest oil fraction. A mathematical model match of the AICV performance is possible via the 10-parameter extended AICD equation, that enables practical evaluation of the AICV in industry standard reservoir simulators. Various scenarios are explored with a conceptual reservoir model and the AICV shows its capacity to reduce water production and enable more gradual and controlled increase in gas-oil-ratio for most scenarios. AICV used in segmented reservoirs shows the largest potential to reduce unwanted fluids and in addition increase oil recovery. In cases with uncertain aquifer and/or gas cap strength, or large variation in effective permeability, the AICV will make an infill well more robust as it autonomously adapts to reality and chokes unwanted fluids and consequently enables more carbon efficient reservoir management.
- North America > United States (0.93)
- Europe > Norway > North Sea > Northern North Sea (0.28)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > Våle Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > A2 North Heimdal T60 Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Hermod Formation > Våle Formation (0.99)
- (37 more...)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Flow control equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- (6 more...)
Abstract The emergence of "big data" has encouraged the utilization of data from various origins to enhance the decision-making process. Unfortunately, multiphase flow studies are often performed in "silos" – within which specific experiments were performed and based on which certain model improvements were proposed. As such, it is easy to lose sight of the big picture of where we are in terms of our understanding and modeling capability. This disconnected approach has also produced an ever-growing, potentially unmanageable list of closure relationships, which can be counter-productive for model development. In this paper, we present exploratory data analyses to comprehensively evaluate the performance of a steady-state multiphase flow point model in predicting high-pressure near-horizontal data from independent experiments. This effort provides wide-ranging hindsight that can reflect the current state-of-the-art of multiphase flow modeling and pinpoint areas where improvements are needed. First, relevant multiphase flow datasets from the literature are collected. In this paper, we limited the scope to near-horizontal and high-pressure data (gas density of 5 kg/m or higher). Then, we run a state-of-the-art model and compare its prediction against these datasets. Multidimensional discrepancy plots are presented to map the models’ performance for pressure drop and holdup predictions across the selected scaling variables. Violin plots are used to identify and analyze the outliers with respect to modeling errors. Confusion matrices are used to quantitatively analyze the model performance in predicting flow patterns, eliminating the restriction of traditional flow pattern map analysis that is limited to qualitative assessment at constant pipe and fluid properties. Finally, the accuracies of key closure relationships are also evaluated. The multidimensional discrepancy plots highlight the conditions where the model performs poorly: low-liquid loading upward flow, downward flow, and high gas flow rates. The violin plots enable quick identification of outliers, which can represent both model and measurement deficiencies. The confusion matrix indicates that the transition between stratified and annular flow is very poorly predicted. The misclassification between stratified and intermittent flow comes at a distant second in terms of occurrence frequency; however, it contributes more significantly to the bulk parameters prediction errors. Except for the slug translational velocity, most closure parameters are still poorly predicted. Entrainment fraction deserves special attention given the expected importance of it on the stratified flow model accuracy. The closure relationships for slug characteristics are unable to predict pseudo-slug flow data accurately. This paper presents several Exploratory Data Analysis (EDA) techniques that enable comprehensive analyses of several independent datasets from various origins. The analyses provide actionable and more general insights that would be otherwise obscured if individual datasets are analyzed in silos, such as operating conditions where higher uncertainty margins need to be applied and where further modeling improvements are desirable.
- Europe (1.00)
- North America > United States > Texas (0.67)
- Overview > Innovation (0.48)
- Research Report > New Finding (0.46)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract Machine learning (ML) models offer intriguing alternatives for multiphase pipe flow simulations. Certain subsets of ML algorithms are computationally robust and may outperform physics-based models when applied within the training range. However, they tend to deteriorate on extrapolations, which are exceedingly common for multiphase flow applications at the industrial scale. "Hybrid" (a combination of ML and physics-based) models conceptually combine the strengths of the physics-based (extrapolability and interpretability) and ML models (adaptability and computational simplicity). In this paper, the author presents an accuracy comparison between a "pure" ML model, a hybrid model, and a high-definition or high-fidelity physics-based model (HD) in a multiphase flow application, which illustrates the benefits and drawbacks of each modeling option. The author implemented two data-driven models to predict the liquid holdup in gas-liquid stratified flow in pipes: a pure ML and a hybrid model. Their accuracies are benchmarked against an HD stratified flow model. The pure ML model uses a neural network (NN) to predict liquid holdup directly. The hybrid model involves a 1D steady-state, fully developed, two-fluid conservation equations, coupled with NN to predict the interfacial friction. The HD model couples the aforementioned conservation equations with a preintegrated 2D velocity profile model, offering a physically self-consistent friction model for fluid-wall and fluid-fluid interfaces. The author collected more than 7,000 laboratory data points from various sources and split them [into training, cross validation (CV), and testing sets] in multiple ways. The splitting mechanism is a unique feature of this paper. The first split ensures the training and testing sets share similar characteristics while the others intentionally impose extrapolation between the two sets. The hybrid model is shown to be more scalable than the pure ML model, albeit performing worse on training. It is also worth noting that the inclusion of physics may reduce the size of relevant training data. The use of dimensionless features improves the pure ML model's extrapolability, although the hybrid model remains superior. The HD model is more accurate and consistent across different data sets than the hybrid model, indicating that it is not always straightforward to reduce the physics to a minimum and task an ML model to compensate for the loss. Furthermore, the inclusion of physics seems to reduce model susceptibility to data noise. The author concludes that physics-based model development remains imperative for advancing the multiphase flow modeling state-of-the-art. In this paper, the author discusses the potentials and challenges for a possible hybrid modeling scheme, in which ML is used as a substitute for a key closure for the physics-based model. This paper can serve as a valuable case study in engineering applications where ML implementation best-practices or workflows are not established yet, such as in multiphase pipe flow or flow assurance.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Summary/Review (1.00)
- Research Report > New Finding (0.66)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-41 > Tubarao Tigre Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-41 > Tubarao Gato Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-41 > Pipeline Field (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Investigation of Lightweight Drilling Fluids for Stability, Properties, and Performance at Downhole Conditions Through a Novel Pilot Facility
Bhagwat, Swanand (Southwest Research Institute) | Wileman, Angel (Southwest Research Institute) | Gutierrez, Luis (Southwest Research Institute) | Rao, Sai (ExxonMobil Upstream Research Company) | Gupta, V. Paul (ExxonMobil Upstream Research Company)
Abstract This paper describes the methods developed for testing and qualification of novel lightweight drilling fluids (foams, glass-bead fluids) using a unique pilot-scale test facility (PSTF). The performance criteria included fluid stability, rheology, pressure transmission, and gas migration under downhole conditions. Test results demonstrating the methods developed are provided, along with the capabilities of the facility, custom fixtures, and equipment that were built to study the performance of these fluids. A set of performance criteria and testing requirements were initially developed, which were then used to design and fabricate a novel pilot facility. The PSTF could generate downhole drilling conditions of 7,500 psig and temperatures above 300°F. Three custom-instrumented test articles were built to simulate wellbore geometry; one 10-ft long and one 18-ft long, both with a 2.62-in ID. The third article had a 10-ft long 6-in × 4-in annulus, with the eccentric internal pipe capable of 100-rpm rotation to mimic the drill string. The test articles could incline up to 45° to simulate deviated wells. Gas could be injected, and its migration rate measured in static and countercurrent flow using a video camera with full-bore sight glass, and gamma-ray densitometers. Dedicated sections for foam generation, measuring density, rheology, pressure transmission, and fluid sampling and imaging were provided. Upon commissioning of the PSTF, a 1 1/2 year test program was successfully carried out using lightweight foams and hollow glass-bead fluids. Due to the novel nature of the tests, best practices and procedures were developed through experimentation to quantify static and dynamic fluid stability, gas migration, foam generation techniques, fluid imaging and characterization, pressure transmission, and rheology. A variety of measurement techniques and instrumentation were trialed in the test articles to determine the best methods for tracking gas migration. Experiments in the test articles yielded a large amount of performance data, including fluid stability over time at different temperature and pressure conditions, the impact of drill string rotation on fluid stability, migration velocities of gas bubbles (i.e., gas kicks) within the drilling fluids at stagnant and countercurrent flow conditions, and the impact of drill string rotation. Pressure transmission speeds were measured in the foam with varying gas fractions. Example datasets from the testing program are provided, along with detailed descriptions of the test methods. The methods and test facility used to study lightweight drilling fluids are unique to the authors’ knowledge. For the first time, drilling fluids were analyzed in an annulus with a rotating pipe at downhole conditions at a pilot scale, and fluid stability along with gas migration were studied. These provide for rigorous testing of lightweight drilling fluids; the application of these fluids is expected to increase with declining reservoir pressures in oil and gas fields.
- Europe (0.46)
- North America > United States > Texas (0.28)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Multiphase flow (1.00)
- (6 more...)