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Junyu, You (College of Petroleum and Natural Gas Engineering, Chongqing University of Science and Technology) | William, Ampomah (Petroleum Recovery Research Center) | Qian, Sun (Petroleum Recovery Research Center)
Abstract This paper will present a robust workflow to address multi-objective optimization (MOO) of CO2-EOR-sequestration projects with a large number of operational control parameters. Farnsworth Unit (FWU) field, a mature oil reservoir undergoing CO2 alternating water injection (CO2-WAG) enhanced oil recovery (EOR), will be used as a field case to validate the proposed optimization protocol. The expected outcome of this work would be a repository of Pareto-optimal solutions of multiple objective functions, including oil recovery, carbon storage volume, and project economics. FWU's numerical model is employed to demonstrate the proposed optimization workflow. Since using MOO requires computationally intensive procedures, machine-learning-based proxies are introduced to substitute for the high-fidelity model, thus reducing the total computation overhead. The vector machine regression combined with the Gaussian kernel (Gaussian -SVR) is utilized to construct proxies. An iterative self-adjusting process prepares the training knowledgebase to develop robust proxies and minimizes computational time. The proxies’ hyperparameters will be optimally designed using Bayesian Optimization to achieve better generalization performance. Trained proxies will be coupled with Multi-objective Particle Swarm Optimization (MOPSO) protocol to construct the Pareto-front solution repository. The outcomes of this workflow will be a repository containing Pareto-optimal solutions of multiple objectives considered in the CO2-WAG project. The proposed optimization workflow will be compared with another established methodology employing a multi-layer neural network to validate its feasibility in handling MOO with a large number of parameters to control. Optimization parameters used include operational variables that might be used to control the CO2-WAG process, such as the duration of the water/gas injection period, producer bottomhole pressure (BHP) control, and water injection rate of each well included in the numerical model. It is proven that the workflow coupling Gaussian -SVR proxies and the iterative self-adjusting protocol is more computationally efficient. The MOO process is made more rapid by squeezing the size of the required training knowledgebase while maintaining the high accuracy of the optimized results. The outcomes of the optimization study show promising results in successfully establishing the solution repository considering multiple objective functions. Results are also verified by validating the Pareto fronts with simulation results using obtained optimized control parameters. The outcome from this work could provide field operators an opportunity to design a CO2-WAG project using as many inputs as possible from the reservoir models. The proposed work introduces a novel concept that couples Gaussian -SVR proxies with a self-adjusting protocol to increase the computational efficiency of the proposed workflow and to guarantee the high accuracy of the obtained optimized results. More importantly, the workflow can optimize a large number of control parameters used in a complex CO2-WAG process, which greatly extends its utility in solving large-scale multi-objective optimization problems in various projects with similar desired outcomes.
Abstract The multi-stage fracture treatments create complex fracture networks with various proppant type, size, and concentration distributed within and along fractures through reservoir rock, where larger size and higher concentrations usually result in higher long-term conductivity. To model the fracture conductivity reduction with depletion, we traditionally use a single monotonic relationship between fracture conductivity and pressure, which is proper for a single proppant concentration but obviously hard to describe the situation in the horizontal wells with complex concentration distributions. This paper is to present a new method to speed-up the calibration process of well performance models with multi-million cells and its two applications in the Wolfcamp reservoir in the Delaware Basin. To study well performance and completion effectiveness of 3000 horizontal wells over University Lands acreage in the Permian Basin, we have built a series of well performance models with complex fracture networks (SPE 189855 and 194367). We have used those models to methodically investigate the drivers of well completion parameters and well spacing on well performance and field development value (URTeC 554). In the process of building multiple robust well performance models, we found out it is hard and time-consuming to calibrate a well performance model with multi-million cells based upon a single correlation between fracture conductivity and pressure. We first modeled the complex fracture networks and fracture conductivity distributions based upon the historical completion pumping data; we then developed multiple correlations to characterize fracture conductivity reduction and closure behaviors with pressure depletion based upon initial fracture conductivities (as the result of proppant type, size, and concentration) and reservoir geomechanical properties. We found out that this method significantly reduced our model calibration time. We then applied our method to multiple case studies in the Permian Basin to test and improve the method. We have thus developed a method to mimic the fracture conductivity reduction and closure behavior in the horizontal wells with complex fracture networks. The paper will layout the theoretical foundation and detail our method to develop the multiple correlations to model fracture conductivity reduction and fracture closure behaviors in the horizontal well performance models in the unconventional reservoirs. We will then show two case studies to illustrate how we have applied our method to speed up the model calibration process. Based upon the multiple applications into our model calibration process, we have concluded that the method is very effective to calibrate the well performance model with complex fracture networks. The method can be used for engineers to simplify and speedup calibrating horizontal well performance models. Therefore, engineers can more effectively build more robust well performance models to optimize field development plans in the unconventional reservoirs.
Abstract The geothermal energy is one of the most promising sources of electricity on the planet; it is available almost anywhere on the continents and resources are inexhaustible. The realization of these possibilities requires solving the problems of deep wells (6-10 km) construction, when the lower horizons are practically impermeable crystalline basement rocks. For effective use of the Earth's heat, bottomhole temperatures must be within 200-300°C. World experience of such deep wells construction is very limited, some examples are given in this work. Known schemes of geothermal energy application requires at least two wells construction - for cold fluid injection and superheated fluid production. The rock - circulating fluid heat exchange in the bottomhole requires drilling of inclined, horizontal, or multi-lateral boreholes and hydraulic fracturing application. Such technologies are widely used in the oil and gas fields, but not in crystalline rocks. The article presents an analysis of the prospects for the geothermal wells construction efficiency increasing by using modern directional drilling systems, drilling with casing, technologies for complications eliminating. The possibilities of using alternative hard rock drilling methods by enhancing the standard formation destruction with drill bits are discussed. These are hydraulic hammers, high-pressure abrasive and fluid jets, laser drilling. A fundamentally new plasma drilling technology is considered. The most serious limitation of alternative drilling prospects is the need of additional "supply lines" to the bottom: high-pressure fluid; electricity; a plasma forming agent, etc. In this regard, options are being considered for the development of continuous drill strings such as coiled tubing, umbilical, flexible composite systems like subsea pipelines. Some of technological solutions for deep geothermal wells construction, and implementation of petrothermal energy schemes for potential projects are proposed. The paper provides an idea of the geothermal well construction technologies, which can ensure the implementation of advanced geo-energy schemes. The problems of geothermal engineering and possible solutions to overcome them, which will contribute to the development of geothermal energy, as the most effective option for decarbonization, are indicated.
Abstract Evaluating Electrical Submersible Pumps (ESPs) [SS1] [NA2] run-lives and performance in unconventional well environments is challenging due to many different factors -including the reservoir, well design, and production fluids. Moreover, reviewing the run-lives of ESPs in a field can be rather complex since the run-life data is incomplete. Often ESPs are pulled while they are still operational, or the ESP has not been allowed to run until failure. These are some of the complications that arise when gauging ESP performance. A large dataset of ESP installs was assessed using Kaplan-Meier survival analysis for the North American unconventional application to better understand those factors that may affect ESP run lives. The factors were studied including but are not limited to the following: Basin and producing formation Comparing different ESP component types such pumps and motors, and new or used ESP components Completion intensity of the frac job (lb/ft of proppant) Kaplan-Meier survival analysis is one of the commonly used methods to measure the fraction or probability of group survival after certain time periods because it accounts for incomplete observations. Using Kaplan-Meier analysis generates a survival curve to show a declining fraction of surviving ESPs over time. Survival curves can be compared by segmenting the runlife data into buckets (based on different factors), therefore to analyze the statistical significance of each and how they affect ESP survivability. Kaplan-Meier analysis was performed on the aforementioned dataset to answer these questions in order to better understand the factors that affect ESP runlives in North American unconventional plays. This work uses a unique dataset that encompasses several different ESP designs, with the ESPs installed in different North American plays. The observations and conclusions drawn from it, by applying survival analysis, can help in benchmarking ESP runtimes and identifying what works in terms of prolonging ESP runlife. The workflow is also applicable to any asset in order to better understand the drivers behind ESP runlife performance.
Abstract There are mainly two types of solids in the oil field waters; Suspended Solids (SS) and Total Dissolved Solids (TDS). While it is easy to remove SS from water, removal of TDS requires the application of advance filtration techniques such as reverse osmosis or ultra-filtration. Because these techniques cannot handle high volumes of the oilfield waters with high TDS content, produced waters originated from hydraulic fracturing activities cannot be treated by using these advance technologies. Thus, in this study we concentrated on the pretreatment of these waters. We investigated the feasibility of the Coagulation, Flocculation, and Sedimentation (CFS) process as pretreatment method to reduce mainly SS in Produced Water (PW) samples. We collected samples from 14 different wells in the Permian Basin. First, we characterized the water samples in terms of pH, SS, TDS, Zeta potential (ZP), Turbidity, Organic matter presence and different Ion concentration. We tested varying doses of several organic and inorganic chemicals, and on treated water samples we measured pH, TDS, SS, Turbidity, ZP and Ions. Then, we compared obtained results with the initial PW characterizations to determine the best performing chemicals and their optimal dosage (OD) to remove contaminants effectively. The cation and anion analyses on the initial water samples showed that TDS is mainly caused by the dissolved sodium and chlorine ions. ZP results indicated that SS are mainly negatively charged particles with absolute values around 20 mV on average. Among the tested coagulants, the best SS reduction was achieved through the addition of ferric sulfate, which helped to reduce the SS around 86%. To further lessen SS, we tested several organic flocculants in which the reduction was improved slightly more. We concluded while high TDS in the Permian basin does not implement a substantial risk for the reduction of fracture conductivity, SS is posing a high risk. Our study showed, depending on components of the initial PW, reuse of the pretreated water for fracturing may minimize fracture conductivity damage.
Abstract This paper presents a simple method to model boundary-dominated flow in hydraulically fractured wells, including horizontal wells with multiple fractures. While these wells are almost always producedat more nearly constant BHP rather than constant rate, use of material-balance time transforms variable-rate production profiles to constant-rate profiles, allowing us to use the pseudo-steady-state (PSS) flow equation for modeling. However, the PSS equation requires use of shape factors in applications, and shape factors available in the literature are available only for square-shaped bounded reservoirs with hydraulic fractures. In this work, we derived shape factors for wells centered in rectangular-shaped drainage areas with different length-to-width aspect ratios. The superposition principle can be used to transform transient radial flow and transient linear flow solutions into bounded reservoir solutions. At large times (when boundary-dominated flow is established), results from these solutions are similar to those obtained from the PSS equation. Therefore, for a pre-defined reservoir geometry, pressure drop values from superimposed transient flow equationscan be substituted back into the PSS equation to calculate shape factors for that reservoir geometry.We used shape factors previously presented by other authors for square drainage areas to validate themethod before applying it to calculate shape factors for more general drainage area configurations. We present shape factors for different fracture half-length to fracture-spacing ratios ranging from 0.2 to 10. Calculated shape factors, when plotted against the fracture half-length to fracture-spacing ratio, produced a smooth curve which can be used to interpolate shape factor values for other fracture configurations. We present applications of this methodology to example low-permeability wells. The use of the PSS equation for wells with vertical fracturescan be extended to multi-fractured horizontal wells (MFHWs) by incorporating the number of fractures in the equation; hence, shape factorsderived for wells with vertical fractures can also be used for MFHWs. Although our results are rigorously correct only for fluids with constant compressibility, use of pseudo-pressure and pseudo-time transformations extend application to compressible fluids, notably gases. Using the PSS equation in production data analysis allows us to calculate contributing reservoir volume and drainage area in a simple manner not requiring use of specialized software.
Donald A., Anschutz (PropTester, Inc.) | Patrick J., Wildt (PropTester, Inc.) | K. Michelle, Stribling (PropTester, Inc.) | Jim, Craig (Sintex Minerals & Services) | Luiz R., Curimbaba (Mineracao Curimbaba LTDA) | Pedro, Silva (Sintex Minerals & Services) | Ibrahim S., Abou-sayed (i-Stimulation Solutions Inc.)
Abstract While the shale revolution flourished prior to the pandemic, the increased supply bubble had already taken a toll on the profitability of horizontal wells with multiple transverse fractures. A significant shift previously occurred to reduce proppant costs by utilizing cheaper, smaller grained, lower strength, and broadly diverse grain sized sands. Due to the extremely low matrix permeability in active unconventional plays, the use of regional 40/70 and 100 mesh sands (50/140, 70/140, etc.) has become commonplace with adequate results. What remains is the need for enhanced conductivity near the wellbore to handle the radial flow convergence loss when the well is brought on-line. Research is being conducted to better understand how to efficiently increase near-wellbore conductivity using lead and tail-in stages with higher permeability (ceramic) proppant when frac sand is the majority of the material pumped into the well. A 10’x20’ Large Slot Flow (LSF) apparatus, equipped with multiple injection points, side-panel ports for leak-off and/or post-test injection, with the ability to be disassembled for sample analysis after testing, was utilized for this project. For this data, the inlet was moved to the centerline of the wall to allow for proppant and fluid to transport into an environment similar to a horizontal wellbore connecting with a transverse fracture. Various tests were conducted to study the depositional characteristics of lead and tail-in stages with ceramic proppant (15% BW-Lead, 5% BW-Tail) and a main stage of 100 mesh sand (80%). Three inlet positions were established in the lower, middle, and upper portion of the apparatus. Tests were recorded to visually capture the efficiency of placing the premium proppants near the wellbore for increased conductivity. A key addition to the study was the innovative, post-production analysis through the side-panel ports. Fluid was injected into the proppant pack to observe the effect of increased near-wellbore conductivity. To improve visibility, the fluid was colored with a fluorescent dye and observed under black lights. The injection front geometry was radial initially, but typically elongated toward the exit point after contacting the ceramic proppant. The amount of time and distance for the fluid to travel through the sand pack, as well as that for the fluid to reach the offtake point once the ceramic bed was reached, were monitored and recorded. The ratio of the velocities should represent a valid qualitative indication of the conductivity contrast of the two proppants. This paper will describe the unique experimental configuration, outline the testing program for both deposition and post-production assessments performed on the deposits, along with results that could provide better design practices leading to improved transverse fracture performance.
Ramiro-Ramirez, Sebastian (The University of Texas at Austin) | Flemings, Peter B. (The University of Texas at Austin) | Bhandari, Athma R. (The University of Texas at Austin) | Jimba, Oluwafemi Solomon (Equinor US)
Abstract We measured steady-state liquid (dodecane) permeability in four horizontal core plugs from the middle member of the Bakken Formation at multiple effective stress conditions to investigate how permeability evolves with confining stress and to infer the matrix permeability. Three of the four tested samples behaved almost perfectly elastically as the hysteresis effect was negligible. In contrast, the fourth sample showed a permeability decrease of ~40% at the end of the test program. Our interpretation is that the closure of open artificial micro-fractures initially present in the sample (based on micro-CT imaging) caused that permeability hysteresis. The matrix permeability to dodecane (oil) of the tested samples is between ~50 nD and ~520 nD at the confining pressure of 9500 psi. The 520 nD sample exhibited the lowest porosity, the highest calcite content, and the largest dominant pore throat radii. In contrast, the 50 nD sample was more porous, and exhibited the highest dolomite content and the smallest dominant pore throat radii. This study shows that our multi-stress testing protocol allows the study of the permeability hysteresis effect to interpret the matrix permeability. We also document the presence of middle Bakken lithologies with permeabilities up to one order of magnitude greater than others. These permeable lithologies may have a significant contribution to well production rates.
This paper reviews the properties of iron compounds (such as iron oxides, iron hydroxides, and iron sulfides) and their impact in shale produced water treatment with an emphasis on the colloidal form of these compounds (small particle size, high surface charge). A wide range of problems is associated with these compounds in produced water including emulsion stabilization, oil-coated solids, pad formation in separators, pipeline solids, and plugging of water disposal formations. In conventional oil and gas production, the role that iron plays and the mitigation strategies for these problems are reasonably well known. In the burgeoning shale industry, the situation is quite different. Not only are iron concentrations significantly higher than in conventional produced water, but the colloidal properties of iron compounds are only recognized by a handful of specialists. In addition, other colloidal particles such as clays and silts are also present at high concentrations in the produced water. Produced water treatment to remove solids in Permian shale produced water is rather hit or miss. We were brought to this realization a couple years ago when testing formation plugging in Permian disposal wells.
Expanding its holdings further in the Delaware Basin, WaterBridge Holdings closed a transaction with Colgate Energy to acquire the produced water infrastructure associated with Colgate's purchase of Occidental acreage in June. The companies entered into a 15-year produced water management agreement for all of Colgate's operated acreage within Reeves and Ward counties, Texas. The acquired assets include 10 water-handling facilities and associated water midstream infrastructure with aggregate handling capacity of approximately 100,000 B/D and approximately 50 miles of produced water pipelines. WaterBridge will manage the produced water infrastructure and integrate these assets into its broader southern Delaware operations. WaterBridge and Colgate have consolidated existing produced water management contracts into a new produced water management services agreement in which Colgate has dedicated all the operated acreage recently acquired from Occidental and the legacy Colgate and Luxe Energy acreage previously dedicated to WaterBridge.