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Collaborating Authors
Facilities Design, Construction and Operation
Abstract Carbon Capture and Storage (CCS) has gained recognition as a mitigation strategy for reducing the accumulation of atmospheric CO2. However, the injection of CO2 into storage reservoirs can lead to increased pore pressure, which in turn induces stress changes in and around the injection site. These stress changes may give rise to several geomechanical hazards, including caprock failure, ground surface uplifting, and induced seismic activity. To address this concern, we have developed a novel optimization approach aimed at maintaining the caprock integrity during the storage of CO2 in geologic formations under geological uncertainty. The developed workflow integrates advanced numerical optimization algorithms with coupled multiphase flow-geomechanics-fracturing models for simulating the response of the storage reservoir to CO2 injection. Using the geomechanical response of the simulation, we define and quantify the potential caprock failure and CO2 leakage risks. An optimization formulation is used to minimize the risk of caprock fracturing and CO2 leakage by finding the optimal distribution of dynamically changing CO2 injection rates across several wells throughout the injection period. The results are extended to incorporate the uncertainty in the simulation model through ensemble-based optimization. The proposed optimization approach identifies the well injection schedule (flow rate vs. time profile) to minimize the risk of caprock fracturing by distributing the pressure increase in the heterogeneous reservoir. The optimization process is designed to continually enhance the injection strategy, aiming to minimize the potential for caprock fracturing by maximizing the stress differences between the minimum effective stress and the fracture opening stress. The paper highlights the importance of employing coupled flow and geomechanics, along with fracture mechanics, in accurately modeling and predicting the potential CO2 leakage. This approach enables the development of injection strategies that prioritize caprock integrity, effectively addressing the challenges associated with optimizing CO2 storage while minimizing the risk of caprock failure.
- Geology > Petroleum Play Type (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
Abatement of GHG Emissions by Simplifying Field Architecture with Multiphase Flowmeters in Onshore US Shale: A Field Case Study
Plagens, J. (Ensign Natural Resources, Houston, Texas, USA, now with Magnolia Oil & Gas) | Moncada, K. (SLB, Houston, Texas, USA) | Thompson, J. (SLB, Houston, Texas, USA) | Husoschi, L. (SLB, Houston, Texas, USA) | Theuveny, B. (SLB, Houston, Texas, USA) | Amin, A. (Belsim S.A., Sugar Land, Texas, USA)
Abstract Methane is a powerful greenhouse gas (GHG). Over 20 years, it is 80 times more potent at warming than carbon dioxide, with onshore conventional wellsite production facilities being the source of more than 50% of petroleum methane emission in the United States (US). An operator working in the gas condensate window of the Eagle Ford shale has been diligently looking for innovative transition technologies to help minimize methane emissions from wellsite sources. Other key sustainability attributes for the project were capex and opex savings while simplifying well-pad architecture. Leak detection and repair (LDAR) programs that identify unintended or fugitive emissions from equipment in an oil and gas facility are a traditional way to drive maintenance activities to reduce emissions. However, this is focused on detection rather than elimination. The operator typically configures well-pads with three to six wells with one test separator per well, resulting in multiple separators per well-pad. The switch from test separators to full gamma-spectroscopy/Venturi combination surface multiphase flowmeters (MPFM) was an ideal solution as it eliminates the need for so many test separators, thus eliminating valves, pneumatic devices, and connections responsible for most fugitive gas emissions on production well sites, while simultaneously delivering real-time monitoring, which provides repeatable and accurate fluid measurements. Over the course of a field trial, the MPFM performed within the uncertainty range specified by the operator and even helped identify bias errors with reference to a test separator to enable remediation. Additionally, the high-frequency data (up to 1 second) helped detect changes in flow behavior like slugging flow or slight changes in water cut. Financial incentive was a significant driver in assessing the MPFM as it provides a 50% reduction in capex per well by simplifying the equipment and pipeline infrastructure and the investment cost for ancillaries (space, power, manifolds, etc.). In addition, overall methane emissions were reduced by an estimated 67%, and the number of potential leak paths for fugitive methane was minimized. Using the field case study, the paper demonstrates how integrating the use of MPFM technology to reduce GHG emissions will bring more tangible results than leak detection and repair efforts. The study shows how emissions can be reduced by more than 72% in different scenarios, depending on the number of wells in a well-pad with one test separator. If the test separator is removed, the reduction can reach up to 92%. Simplifying well-pad architectures using MPFMs for well measurements while performing separation and liquid handling at centralized facilities minimizes the many connections and valves responsible for most methane fugitive emissions. New or retrofitted facilities can use this transforming technology as their cost has decreased significantly, and data are repeatable and accurate.
- Overview (0.46)
- Research Report > Experimental Study (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.50)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Downhole and wellsite flow metering (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- (2 more...)
Abstract The company is embarking on Carbon Capture and Storage (CCS) by injecting CO2 into depleted offshore gas reservoir located in the east coast of the Malaysia Peninsular, as part of the CO2 Decarbonization to achieve Net Zero Carbon Emissions (NZCE) by 2050. One of the main scopes is to evaluate the technical feasibility and viability to repurpose the existing hydrocarbon pipelines for CO2 transportation. This paper aims to share our experiences and the challenges we faced to determine the possibility of utilizing existing hydrocarbon pipelines for CO2 transportation. The pipelines have been in operation for 41 years and have exceeded their design life. This necessitates the Asset Life Extension Study (ALES) to ascertain whether these pipelines can still be operated for another 20 years based on the CCS CO2 injection design life. Following the outcome of the ALES study, inspection and maintenance scopes have been identified to be conducted to ascertain pipeline integrity. Once these have been done, the pipelines will undergo technical assessments and evaluations to establish the integrity, criteria, and operating envelope for the purpose of CO2 transportation for injection. Through various integrated multi-disciplinary workshops held internally utilizing the company's subject matter experts, the followings detail out of the key technical considerations to repurpose the pipelines for CO2 transportation: (1) Pipeline integrity assessment, taking into account current and future operating conditions, as well as Running Ductile Fracture and propagation control. (2) Corrosion assessment and corrosion inhibitor in high CO2 environment. (3) Non-metallic elastomer requalification. (4) Hydraulic analysis including pipeline capacity, phase behavior, and CO2 quality. (5) Process flow assurance study and thermodynamics modeling. (6) Safety evaluation workshop addressing the safety requirements due to CO2 transport. All studies are taking place concurrently and pending completion, with the aim of establishing the Fitness for Service (FFS) for these repurpose pipelines. CCS CO2 injection project is CAPEX intensive, therefore the possibility of repurposing existing hydrocarbon pipelines for CO2 transportation offers an attractive opportunity to offset some of the high investment cost required.
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
An Application of Superhydrophilic Coating to Enhance the Water Film Retention for Core Annular Flow
Wang, W. (Sinopec Dalian Research Institute of Petroleum and Petrochemicals Co. Ltd., Dalian, Liaoning, China) | Li, Z. Z. (Sinopec Dalian Research Institute of Petroleum and Petrochemicals Co. Ltd., Dalian, Liaoning, China) | Wang, X. L. (Sinopec Dalian Research Institute of Petroleum and Petrochemicals Co. Ltd., Dalian, Liaoning, China) | Xue, Q. (Sinopec Dalian Research Institute of Petroleum and Petrochemicals Co. Ltd., Dalian, Liaoning, China) | Liu, M. R. (Sinopec Dalian Research Institute of Petroleum and Petrochemicals Co. Ltd., Dalian, Liaoning, China) | Yang, J. (Sinopec Dalian Research Institute of Petroleum and Petrochemicals Co. Ltd., Dalian, Liaoning, China) | Wang, P. X. (Sinopec Dalian Research Institute of Petroleum and Petrochemicals Co. Ltd., Dalian, Liaoning, China) | Ding, K. (Sinopec Dalian Research Institute of Petroleum and Petrochemicals Co. Ltd., Dalian, Liaoning, China) | Sun, X. Z. (Sinopec Dalian Research Institute of Petroleum and Petrochemicals Co. Ltd., Dalian, Liaoning, China)
Abstract The tremendous viscosity of heavy oil presents significant challenges to the pipeline transportation and efficiency improvement of oil gathering systems, thus prompting the execution of numerous studies that aim to reduce drag. The core annular flow is regarded as one of the most efficient and eco-friendly methods for drag reduction, but its commercial application is limited by the inadequate stability of the water film. In this work, a concept of water film retention enhancement at the pipe wall through superhydrophilic coating is presented, to increase the stability of core annular flow in heavy oil flowlines. Furthermore, a novel measuring method that efficiently evaluates the water film retention enhancement performance of superhydrophilic coating using a rheometer is proposed. This method is more effective, oil-saving, and sensitive compared to conventional flow loop tests. The influence of temperature, shear rate, and water film thickness on water film retention are studied. It was found that the viscosities measured with superhydrophilic coating decreased by approximately 40% at 50 ยฐC and showed a reduced temperature-dependence, compared to the inherent viscosities of heavy oil. This decrease in viscosity was attributed to the lubrication provided by the water film. The viscosities measured with coating were also found slightly decrease with increasing shear rates from 10 to 120 s, indicating that the water film retention is enhanced by coating and the emulsification of heavy oil and water film is prevented even under strong shear. Moreover, it was observed that the water film thickness had a negligible impact on the measured viscosities as long as the water was sufficient to fully wet the coating. These results verify the feasibility of using superhydrophilic coating to enhance water retention and show a promising possibility of practical application of superhydrophilic coating in core annular flow for transporting heavy oil.
- Asia > China (0.46)
- North America > United States (0.28)
New Insights on Catalysts-Supported in situ Upgrading of Heavy Oil During in situ Combustion Oil Recovery
Fassihi, M. R. (Beyond Carbon, LLC) | Moore, R. G. (University of Calgary, Department of Chemical and Petroleum Engineering) | Pereira Almao, P. (University of Calgary, Department of Chemical and Petroleum Engineering) | Mehta, S. A. (University of Calgary, Department of Chemical and Petroleum Engineering) | Ursenbach, M. G. (University of Calgary, Department of Chemical and Petroleum Engineering) | Mallory, D. G. (University of Calgary, Department of Chemical and Petroleum Engineering)
Abstract As part of GHG reduction initiatives, there have been many publications on CO2 capture, utilization, and storage (CCUS), reducing the carbon footprints in the oil and gas production, switching to renewable energies, and generating carbonless fuel (e.g., H2) via in situ processes. In situ upgrading of bitumen and heavy oils and converting them into low sulfur, low N2, and low asphaltene can help with both producing cleaner fuel as well as utilizing vast resources of energy that could otherwise be wasted due to extreme measures of no fossil fuel policies. Additionally, such processes could produce valuable products, enhanced shipping/pipelining, and less demanding downstream processing. Generating hydrogen could be another focus area for in situ upgrading. This paper provides new insights into the results of several combustion tube tests that were performed for Alberta Ingenuity Centre for In Situ Energy (AICISE) using different heavy oils with fresh supported catalyst. The catalysts were placed in the production end of the combustion tube so oil would pass over the catalyst bed before being produced. In practice, solid catalyst particles could be placed into the oil-bearing formation adjacent to the producing wellbore, ensuring that crude oil will flow over the catalysts during oil production. This paper utilizes many of the lab results that have never been published before. The objective is to understand whether using catalysts has merits in our future oil production activities under the current environmental restrictions. A commercial Ni/Mo catalyst was used in these tests. The results of these tests indicated at least temporary significant occurrence of reactions such as: hydroprocessing (HP), hydrotreating reactions, such as hydrocracking (HC), hydrodesulfurization (HDS), hydrodenitrogenation (HDN) and hydrodeoxygenation (HDO). We will discuss the impact of pressure, temperature, water injection and dispersed versus supported catalysts on the degree of oil upgrading. Also, the key parameters that could impact in situ hydrogen generation will be presented. Specifically, the role of reactions such as Aquathermolysis (AQ), thermal cracking (TC), water-gas shift reaction (WGS) and coke gasification (CG) will be discussed. Notice that the products of these reactions could undergo additional methanation reactions (ME) which could reduce the H2 concentration in the produced gas. Finally, methods of upscaling these results to the field conditions will be presented.
- North America > United States (1.00)
- North America > Canada > Alberta (0.66)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- (2 more...)
Abstract This publication is aimed to show the potentiality of FluidMagic, an Equinor in-house developed software tool, for analysis, decision making, and production follow up. The tool was proven to be successful in differentiating from the gas in solution, gas condensate and injection gas produced by wells, and at the same time, it was able to provide estimates of the proportion of free reservoir oil produced in the Gina Krog field in the Norwegian Continental Shelf. Developed in Python, this innovative software tool is powered by a sophisticated regression algorithm that recombines andโฏmodifies the reservoir fluids to match reported test separator volumes andโฏdensities. Individual well downhole pressure and temperature, as well as fluid rates from test separator and measured gas-liftโฏrates are used as input. FluidMagic outcomes were validated by a compositional reservoir numerical simulation model usedโฏto generate synthetic testโฏseparator data. For this purpose, the gas tracer option was enabled to track the produced injectionโฏgas fraction. Results showed a perfect conversionโฏfrom test separatorโฏrates to process rates, along with a near perfectโฏestimation of wellโฏstream flowingโฏcompositions. In addition, remarkably accurate allocationโฏof reservoir fluid andโฏinjection gasโฏproduction was achieved. Early gas breakthrough in Gina Krog oil wells had been observed just months after production start-up and even before gas injection started. This created challenges when it comes to computing the amount of gas being recirculated throughout the oil producers with high GOR. Estimating recycled gas amounts became crucial to maximize the free reservoir oil production from the oil rim and liquid production from the gas cap. FluidMagic then became the key enabler to utilize the massive amount of data collected daily from the test separator by allowing the quantification of the corresponding allocated surface oil and gas production from well stream.โฏImplementation of FluidMagic in Gina Krog field have proven to be effective for: quantification of the injected dry gas volumes that had been back producedโฏby specific wells in the field, in the determination of individual well stream composition, for evaluation of the well intervention (zone isolation) efficiency as well as for gas tracer breakthrough timing confirmation. This novel approach provides the ability to accurately allocate production at reservoir and surface level virtually at real-time based on daily production data from test separator, avoiding frequent updates to the rather complex and time-consuming compositional reservoir numerical model. Similarly, this methodology minimizes the need for frequent fluid sampling in connection toโฏfeed composition predictions.
- Europe > Norway > North Sea > Hugin Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 303 > Block 15/6 > Gina Krog Field > Hugin Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > South Viking Graben > PL 303 > Block 15/5 > Gina Krog Field > Hugin Formation (0.99)
- (70 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
- Information Technology > Modeling & Simulation (0.88)
- Information Technology > Software (0.68)
Abstract The accumulation of liquid in deeper wells poses a critical problem as it significantly reduces the well's productivity index. One of the methods used to lift the accumulated liquid is the sucker rod pump system (SRP). However, lifting large volumes of liquid and associated gas to the surface artificially has been challenging, particularly with rod pump systems. To address this issue, a downhole gas separator can effectively be deployed below the pump intake to separate the free gas from the produced liquid. The gas separated downhole can then be extracted through the tubing-casing annulus while the liquid is artificially lifted through the tubing. The paper endeavors to provide a comprehensive review of recent advancements, technologies, and challenges related to downhole gas-liquid separators. The findings of this study can serve as a valuable guide for the development of downhole gas-liquid separation technologies in the industry, particularly for installation in unconventional wells. This review includes various laboratory evaluation tests and field examples that outline the efficiency and reliability of some downhole gas-liquid separators. There are two approaches implemented to design separators. The first approach is called static gas separation, based on the gravity principle. The second approach is dynamic gas separation, which is based on applying centrifugal forces through rotational speed. However, several downhole gas-liquid separators have low efficiency and lack an acceptable guideline for their optimum design. In some fields that suffer from liquid loading problems, it may be imperative to design and install an SRP and a downhole gas-liquid separator, to prevent gas lock problems. Based on the reviewed literatures, it was shown that centrifugal separators had better gas/liquid separation efficiency comparing to gravitational separators. Cyclone centrifugal separators consistently exhibit separation efficiencies ranging from 90% to 98%, whereas gravity-based separators typically achieve efficiency levels between 70% and 90%, depending on the design and operational variables. Centrifugal separators consistently deliver exceptional separation efficiencies, with effectiveness ranging from 90% to 99%. Moreover, the swirl tubes have showcased an approximate separation efficiency of 90% and effectively handle the fluctuating gas flow rates encountered in the well. This review comprehensively examines the advancements, limitations, and applications of downhole gas-liquid separators in oil and gas operations, specifically in conjunction with artificial lift systems. The paper aims to bridge the gap and differentiate between different types of downhole separators, offering researchers an extensive guide for their current and future investigations. Additionally, it proposes suitable technologies that can be deployed alongside the sucker rod pump (SRP) to enhance its efficiency in wells facing challenges related to liquid loading.
- Asia > Middle East > Saudi Arabia (0.46)
- North America > United States > Texas (0.28)
- North America > United States > Louisiana (0.28)
- Overview (1.00)
- Research Report > New Finding (0.88)
- Oceania > Australia (0.89)
- North America > United States > Louisiana > China Field (0.89)
- Europe > Russia > Northwestern Federal District > Komi Republic > Timan-Pechora Basin > Pechora-Kolva Basin > Usa Field (0.89)
- Production and Well Operations > Artificial Lift Systems > Beam and related pumping techniques (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Separation and treating (1.00)
Sanding in Response to Dynamic Changes in Downhole Conditions
Xiao, Y. (BP America Inc., Houston, Texas, U.S.A.) | Vaziri, H. (BP America Inc., Houston, Texas, U.S.A.) | Saraswaty, D. (BP Indonesia, Jakarta, Indonesia) | Muhamad, I. (BP Indonesia, Jakarta, Indonesia) | Yusifov, I. (BP Azerbaijan, Baku, Azerbaijan) | Fataliyev, V. (BP Azerbaijan, Baku, Azerbaijan) | Abdellatif, W. (BP Egypt, Cairo, Egypt) | Sheta, I. (BP Egypt, Cairo, Egypt)
Abstract Downhole conditions from the sanding risk viewpoint refer to anything in the downhole that affects rock disaggregation and sandface fluid flux, two principal factors dictating wellโs sanding response. Often times similar wellhead flow rate and pressure may be associated with drastically different downhole conditions and their dynamic changes, resulting in complex and counter-intuitive sanding responses. Due to their practical significance but difficulties in reliably predicting all of them in advance, this paper describes a sanding-physics-based data integration approach to get them consistently identified for the practical purpose of taking the right course of action to safely maximize wellโs flow potential, and prevent, mitigate and manage well-specific sanding issues. It requires a multi-disciplinary effort and cross-referencing well production histories fieldwide is an integral part. Equally important are the prior sanding-mechanisms-based empirical relations between sanding severity and driving factors, refined reservoir engineering simulation, and numerical sanding prediction that considers effects of rock disaggregation, depletion, drawdown, fluid flux and water in one-go. Three field cases are presented to illustrate the approach. Each case is distinctively different although they all involve cased & perforated (C&P) high-rate gas wells in competent formations that have been online for years but without formation water breakthrough yet. In Case-1 uniform reservoir pressure distributions between reservoir formation subunits and production logging tool (PLT) surveys in each well have provided a reliable delineation of gas flux distributions and shut-in induced temporary wellbore water buildups. That has led to a consistent understanding of well specific sanding in relation to high gas flux and water buildups at a low rock disaggregation state. In Case-2 differential reservoir pressures /depletions in different units of a multi-stacked reservoir pay system under a commingled production have resulted in dynamic changes in drawdown, gas flux and downhole water activities, and thus complex sanding responses including prolonged perforation debris cleanout, high drawdown induced sanding and water-crossflow induced sanding during post shut-in production ramping. In Case-3 a thorough review of limited data available in 4 wells has inferred that the interaction between smectite-bearing formation intervals and temporary wellbore water buildups and its limited near-wellbore damage and subsequent self-cleanup under drawdown and gas flux are responsible for observed well-specific cyclic changes in drawdown and minor sand events prior to depletion induced rock disaggregation. Despite observed sand production in all 3 fields neither permanent production chokeback nor intervention are needed to date. Rather, well specific sand management strategies and surveillance tailored toward tendencies of well-specific dynamic changes in downhole conditions have been implemented to safely achieve the targeted gas rate.
- North America > United States > Texas (0.28)
- North America > United States > California (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.95)
- Geology > Mineral > Silicate > Phyllosilicate (0.35)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Solids (scale, sand, etc.) (1.00)
Unlocking Stranded Marginal Gas Fields in Malaysia with Low CAPEX Approach
How, L. L. (Vestigo Petroleum, Malaysia) | Farina, N. Norintan (Vestigo Petroleum, Malaysia) | Azmukiff, K. (Vestigo Petroleum, Malaysia) | Osman, Z. (Vestigo Petroleum, Malaysia) | Chang, Y. S. (Vestigo Petroleum, Malaysia) | Shahardin, S. (Vestigo Petroleum, Malaysia) | Azhar, S. Fairudul (PETRONAS, Malaysia)
Abstract Vestigo Petroleum Sdn. Bhd. (VPSB) has been awarded the right to develop and produce gas fields via a Petroleum Sharing Contract in offshore Peninsular Malaysia. The contract area consists of undeveloped Field T, Field I and Field B integrated late life asset. The undeveloped Field T and Field I marginal gas fields lie within 60km from existing Field B production hub. The production comes from gas dominant Field B, a producing field that is in decline and of which VPSB assumed operatorship in 2017. The immediate business driver is rapid monetization of the asset via tapping into nearby potential marginal gas fields. To enable this, low CAPEX and rapid development with fast investment return are required. Among the undeveloped gas fields, Field T was identified to anchor the development as it carries significant discovered gas volume. However, majority of the gas volume comes with H2S, and CO2 content which is beyond sales gas specification. Therefore, inter and intra fields blending were considered. Owing to the complexity of Field T that is dependent on other fields to provide blending medium, it is crucial to outline sequencing, timing of the other gas fields appraisal and development to optimize the development. To start with, Field T development from a wellhead platform tied back to existing VPSB processing facilities via a 60km long pipeline was the identified concept. A standardized wellhead platform, batch drilling and fit purpose well design in conjunction with application of Zap-Lok, mechanical connection technology in pipeline and sharing of operation cost with existing facilities led to cost effective development. This is the first application of Zap-Lok technology offshore Malaysia. The deployment of VPSB standard wellhead platform enabled rapid field development, with platform installed in less than eleven (11) months after project approval. All five (5) development wells were batch drilled to penetrate multiple stacked reservoirs and completed monobore to accommodate selective bottom-up perforation. These monobore wells either commingled minor reservoirs within similar pressure regime or selectively perforated at major reservoirs only for production to meet committed gas rate. This also ensures not to jeopardize major reservoirs gas reserves and reservoir management plan. Future developments are being planned to duplicate the success of Field T development to other identified marginal fields to drive cost reductions over time with higher efficiency.
- Asia > Malaysia (1.00)
- North America > United States > Texas (0.88)
Abstract Gas lift is the preferred method of artificial lift of many operators in the Delaware Basin due to high gas/oil ratio's (GOR). The volumes of produced gas have a high liquid yield creating challenges for gas lift compression and surface facilities. Condensate and water drop-out creates pressure fluctuations, out-of-range conditions, and mechanical failures with compression if not effectively managed. Problems occur when liquid slug-flow or carry-over in the gas stream enters the compressor, leading to low suction pressures, out-of-range compressor discharge pressures, or inter-stage pressure fluctuations. In the Delaware Basin, the smaller compressors, typically used for gas lift, are not optimized to handle these liquid-rich gas conditions. This study presents methodologies to improve equipment designs and operating conditions for gas lift as well as predicting more accurately the fluid conditions of the rich Delaware Basin gas. Run time data has been tracked over multiple years for gas lift compressors used by an operator in West Texas. Key findings show that 53% of shutdowns were caused by process upsets and gas conditions. Shutdowns occurred from liquid drop-out that triggered alarms designed to protect the equipment, or that caused direct mechanical failures of valves, compressor cylinders, and scrubber level controls. In all cases, production was suspended, and every restart of the gas lift compressor required a blowdown, creating lost production, operational intervention, and release of carbon emissions. Gas lift compression is set up for single well or multiple well injection utilizing one compressor. Smaller gas lift compressor packages (less than 250 hp) are typically not engineered specifically for the liquid-rich gas. Insufficiently sized suction scrubbers, pocketed piping arrangements, high BTU gas received from flash gas separator/heater treater, and/or lack of adequate temperature control likely contributed to problems of liquid fall-out carrying over into compressors. In the sample well study, gas and liquid samples were collected to conduct process simulation to predict liquid fall-out in the gas lift system design. The results of this work show that the Delaware Basin requires compressor packages and surface facilities specifically engineered for a unique gas composition. The fluid analysis and its findings aided the compressor provider to redesign the compressor system to keep hydrocarbon liquids in solution during all stages of compression allowing gas lift operations in the Delaware Basin to operate more efficiently with fewer mechanical issues. The new technology derived from this work provided a more effective way to reduce liquids dropping out from the gas stream and improve automation with fewer shutdowns and manned interventions. Overall, better control of gas lift operations was maintained, fugitive methane releases were reduced, and gas production was improved while keeping liquids in the gas stream during compression using a Hot Gas Bypass (HGBP) technique.
- 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...)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Compressors, engines and turbines (1.00)