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Collaborating Authors
Results
A Pilot Demonstration of Flaring Gas Recovery during Shale Gas Well Completion in Sichuan, China
Xue, Ming (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology (Corresponding author)) | Li, Xingchun (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Cui, Xiangyu (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Cheng, Xin (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Liu, Shuangxing (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Xu, Wenjia (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology) | Wang, Yilin (State Key Laboratory of Petroleum Pollution Control, CNPC Research Institute of Safety and Environmental Technology)
Summary As one of the largest emitters in the world, the oil and gas industry needs to apply more effort to greenhouse gas (GHG) reduction. Methane, as a potent GHG, could largely determine whether natural gas could serve as a bridging energy toward a sustainable future. In the past decade, oil and gas companies in China have significantly enhanced casing gas recovery and reduced large volume flaring (>2ร10 m/d). However, the remaining low- to mid-volume flaring gas was left for further recovery. Shale gas production in China has met a surge in the number of drilling wells. Those new wells were characterized by a relatively low gas production rate (<1ร10 m/d) in comparison with shale gas wells in the US. As a result, flaring gas during well completion needs to be recycled or used to enhance the gas recovery rate. In this study, we carried out a pilot demonstration project of flaring gas recovery to reduce GHG emissions in the Weiyuan shale gas region in Sichuan Province, China. We adopted the technical route of dehydration and natural gas compression. The recycled natural gas was transformed into compressed natural gas (CNG) and transported to the nearest CNG station for further use. The inlet gas pressure was between 2.85 and 5.82 MPa, and the outlet pressure was kept stable at around 20 MPa to meet the standard of CNG. The manufactured device also showed sound flexibility with the recovery rate between 523.22 and 1224.38 m/h, which was 28โ157% of the designed capacity. The combination of the molecular sieve with high capacity, post low-pressure dehydration, and the application of hydraulic piston in the compression system have guaranteed the equipment to meet the designed performance. The equipment applied in the pilot demonstration has well matched with the local transportation, gas composition, and surface engineering of the well completion. It has the potential of popularization and application in the shale gas tight gas regions in China. Other technical routes, such as small-scale gas to chemicals or natural gas hydrate, should be considered for industrial application for gas flowing rate less than 2ร10 m/d to ensure a further drive down of methane emission along the value chain.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Health, Safety, Environment & Sustainability > Environment > Air emissions (1.00)
- Facilities Design, Construction and Operation (1.00)
Observation Lateral Project: Direct Measurement of Far-Field Drainage in the Bakken
Cipolla, Craig (Hess Corporation (Corresponding author)) | Wolters, Jennifer (Hess Corporation) | McKimmy, Michael (Hess Corporation) | Miranda, Carlos (Hess Corporation) | Hari-Roy, Stephanie (Hess Corporation) | Kechemir, Aicha (Hess Corporation) | Gupta, Nupur (Hess Corporation)
Summary In 2019, the operator embarked on a very ambitious data acquisition project in the Bakken, with the goal of mapping far-field drainage and characterizing completion performance. The project consisted of a six-well pad (10,000 ft laterals) with a dedicated observation lateral located in the Three Forks (TF) formation instrumented with cemented pressure gauges and fiber optics along the 10,000 ft lateral. The observation lateral was offset by Middle Bakken (MB) wells ~450 ft on either side (~900 ft MB-MB well spacing). One of the MB wells was instrumented with fiber optics for cluster-level completion measurements and โfrac hitโ detection, while the other offset MB well was used to deploy geophones for microseismic mapping. Three different fracture treatment designs were evaluated, with the goal of understanding how fluid volume and rheology, proppant volume and size, and proppant/fluid ratio affect fracture geometry and drainage. Quantitative application of oil and water tracers was used to evaluate the productivity of each treatment design. During the completions of the first three wells, microseismic data provided important measurements to characterize fracture geometry and โoffset wellโ fiber provided strain data to evaluate fracture morphology (i.e., far-field fracture behavior). Stress shadowing was evaluated by combining the microseismic and strain data. These measurements were used to calibrate a hydraulic fracture model to enable more reliable predictions of fracture geometry and morphology. Cluster-level measurements of fluid distribution provided data to support increasing clusters per stage and decreasing stage count. Production has been monitored continuously for more than 12 months, including interference testing to evaluate connectivity. The pressure gauges placed along the observation lateral provided one of the first-ever measurements of far-field drainage as a function of fracture treatment design (450 ft in between two producing wells with 900 ft well spacing). The results show that MB wells can drain the TF at distances of 450 ft, and fracture treatment design can significantly impact drainage and productivity. Although the evaluation, modeling, and trials are ongoing, these results may add significant value by enabling Bakken development with fewer, more productive wells in some portions of the basin.
- North America > United States > North Dakota (0.86)
- Africa > Middle East > Libya > Murzuq District (0.48)
- Information Technology > Communications > Networks (0.68)
- Information Technology > Modeling & Simulation (0.47)
Observation Lateral Project: Direct Measurement of Far-Field Drainage in the Bakken
Cipolla, Craig (Hess Corporation (Corresponding author)) | Wolters, Jennifer (Hess Corporation) | McKimmy, Michael (Hess Corporation) | Miranda, Carlos (Hess Corporation) | Hari-Roy, Stephanie (Hess Corporation) | Kechemir, Aicha (Hess Corporation) | Gupta, Nupur (Hess Corporation)
In 2019, the operator embarked on a very ambitious data acquisition project in the Bakken, with the goal of mapping far-field drainage and characterizing completion performance. The project consisted of a six-well pad (10,000 ft laterals) with a dedicated observation lateral located in the Three Forks (TF) formation instrumented with cemented pressure gauges and fiber optics along the 10,000 ft lateral. The observation lateral was offset by Middle Bakken (MB) wells ~450 ft on either side (~900 ft MB-MB well spacing). One of the MB wells was instrumented with fiber optics for cluster-level completion measurements and โfrac hitโ detection, while the other offset MB well was used to deploy geophones for microseismic mapping. Three different fracture treatment designs were evaluated, with the goal of understanding how fluid volume and rheology, proppant volume and size, and proppant/fluid ratio affect fracture geometry and drainage. Quantitative application of oil and water tracers was used to evaluate the productivity of each treatment design. During the completions of the first three wells, microseismic data provided important measurements to characterize fracture geometry and โoffset wellโ fiber provided strain data to evaluate fracture morphology (i.e., far-field fracture behavior). Stress shadowing was evaluated by combining the microseismic and strain data. These measurements were used to calibrate a hydraulic fracture model to enable more reliable predictions of fracture geometry and morphology. Cluster-level measurements of fluid distribution provided data to support increasing clusters per stage and decreasing stage count. Production has been monitored continuously for more than 12 months, including interference testing to evaluate connectivity. The pressure gauges placed along the observation lateral provided one of the first-ever measurements of far-field drainage as a function of fracture treatment design (450 ft in between two producing wells with 900 ft well spacing). The results show that MB wells can drain the TF at distances of 450 ft, and fracture treatment design can significantly impact drainage and productivity. Although the evaluation, modeling, and trials are ongoing, these results may add significant value by enabling Bakken development with fewer, more productive wells in some portions of the basin.
- North America > United States > North Dakota (0.86)
- Africa > Middle East > Libya > Murzuq District (0.48)
- Information Technology > Communications > Networks (0.68)
- Information Technology > Modeling & Simulation (0.47)
A Well Flux Surveillance and Production Ramp-Up Method for Openhole Standalone Screen Completion
Karaaslan, M. (University of Houston) | Wong, G. K. (University of Houston (Corresponding author) | Soter, K. L. (email: gwong3@uh.edu)) | Hicking, S. H. (Shell Exploration and Production, Co) | Yousif, Majeed H. (Shell International Exploration and Production, Inc.)
Summary Well surveillance requires practical models to balance the reward of maximizing production with the risk of ramping up production too much, which damages the completion. In this paper we present a method to monitor and ramp up production for openhole standalone screen (OH-SAS) completion. The objective is to optimize production using pressure transient analyses to assess the completion impairment and failure risks during the production ramp-up process. The flux model incorporates filter-cake pinholes, which are formed from nonuniform deposition and cleanup of filter cake during drilling and completion operations. Pinholes cause concentrated fluxes and increase completion failure risks. The method comprises three components, which are (1) determine pinhole properties from laboratory tests, (2) relate completion pressure drop of production through pinholes to pressure transient analyses, and (3) distribute fluxes in the standalone screen wellbore. Examples are presented and show that the completion pressure drop as a function of flow rate is nonlinear and higher with pinholes than without pinholes. By not incorporating pinholes, operations can potentially limit ramp-up. Flux distribution examples show that the largest impingement or radial velocity is at the top section of screen. The axial annular flow velocity or scouring velocity is two orders of magnitude larger than the screen impingement velocity. An integrated flux surveillance method for OH-SAS completion is presented for field applications.
- Europe (1.00)
- North America > United States > Texas (0.68)
- Asia > Middle East (0.67)
Summary In recent years, the advancement of horizontal-well technology has played a major role in making oil production economically feasible from many reservoirs. One of the major problems that can reduce the efficiency of using horizontal wells is gas and water coning caused by the heel-toe effect and heterogeneity along the well. To tackle this problem, Equinorโs autonomous inflow-control device (ICD) (AICD), known as rate-controlled production (RCP) valves, is widely used today. RCP valves can effectively delay the early water breakthrough and partially choke back water autonomously after water breakthrough. To fulfill a suitable design of a long horizontal well with the RCP completion, a detailed understanding of multiphase-flow behavior from the reservoir pore to the wellbore and production tubing is needed. Coupling a dynamic multiphase-flow simulator such as the OLGA (Schlumberger Limited, Sugar Land, Texas, USA) simulator with the near-wellbore reservoir module such as the OLGA ROCX module provides a robust tool for achieving this purpose. However, there is no predefined option in the OLGA simulator for implementing the autonomous behavior of the RCP valves directly. Therefore, creating a model of oil production by considering well completion with the RCP valves in the OLGA simulator is challenging. In the previous works, this has been performed by using the Proportional Integral Derivative (PID) Controller option in the OLGA simulator, which controls the opening of an equivalent orifice valve according to the fixed value of the water cut. However, because of the performance of the PID Controller using a fixed setpoint and the difficulties in properly tuning the PID Controller, choosing this option leads to a large degree of inaccuracy in the simulation models. In this paper, by proposing a novel method with a developed mathematical model and a control function for the RCP valves, the autonomous behavior of these valves is implemented in the OLGA simulator. In this new approach, the control signals are calculated using the variation of water cut and introduced to the OLGA simulator through the Table Controller option instead of the PID Controller. The presented approach in this paper can be used for the simulation of water-cut (or gas/oil-ratio) reduction potential of all RCP-type AICDs in reservoirs with different characteristics. However, to explain the procedure of this approach in detail, the near-well oil production from Well 16/2-D-12 in the Johan Sverdrup Field (JSF) considering RCP completion is modeled as a case study. In this study, the simulation model is developed using one of the commonly used types of RCP valves called the TR7 RCP valve. Version 2016.1.1 of the OLGA simulator/ROCX module is used (Schlumberger 2016). According to the simulation results, compared with using ICDs, by the completion of Well 16/2-D-12 with RCPs, the water cut, water-flow rate, and accumulated water production can be reduced by 2.9, 13.3, and 12.1%, respectively, after 750โdays. The results also showed that by using the proposed approach, the autonomous behavior of the RCP valves according to the water-cut variations can be appropriately implemented in the OLGA simulator. This can help engineers and researchers to achieve a better design of a long horizontal well using the RCP completion. Consequently, using this approach can be beneficial for improving technology, optimizing production, minimizing risk, and reducing costs in oil recovery.
- Asia (1.00)
- Europe > Norway > North Sea > Central North Sea (0.54)
- North America > United States > Texas > Fort Bend County > Sugar Land (0.24)
- Overview > Innovation (0.34)
- Research Report > New Finding (0.34)
- Europe > Norway > North Sea > Northern North Sea > South Viking Graben > Vana Basin > RL 088 BS > Block 25/4 > Alvheim Field > Lista Formation > Vรฅle 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 > Vรฅle Formation (0.99)
- (63 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Process simulation (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Piping design and simulation (1.00)
Summary In this paper we highlight a pilot project in which chamber gas lift was installed in two unconventional horizontal wells. Chamber gas lift, a combination of deep gas lift and intermittent gas lift, allows for an efficient, closed completion with the cyclic injection of highpressure gas, which expands and rapidly displaces fluid at high velocity from deep in the well. Development of the system was a collaboration internally and in conjunction with the vendor to install what was historically a vertical-well assembly through the curve section and into a horizontal wellbore. The chamber assembly was successfully designed, sourced, manufactured, installed, and operated. To modify the design from vertical to horizontal applications, components were custom-designed to maintain a sealed chamber. Components deemed most likely to fail are replaceable by slickline intervention. Results indicate a sustained lower downhole pressure than the previous intermittent-gas-lift system, an increase in production, and a good chamber-sweep efficiency. Introduction In gas lift, the injection of high-pressure gas reduces the density of the fluid column, thereby decreasing the bottomhole pressure (BHP), and the resulting pressure differential between the flowing BHP and static BHP induces inflow.
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Wolfcamp Formation (0.99)
Choke-Management Strategies for Hydraulically Fractured Wells and Frac-Pack Completions in Vertical Wells
Karantinos, Emmanouil (University of Texas at Austin) | Sharma, Mukul M. (University of Texas at Austin) | Ayoub, Joseph A. (Schlumberger) | Parlar, Mehmet (Schlumberger) | Chanpura, Rajesh A. (Schlumberger)
Summary In this study, a quantitative method is presented for the selection of a choke-management strategy that minimizes the risk of the predominant failure mechanisms in hydraulically fractured wells and frac-pack completions. In unconventional resources, an improper choke-management strategy may trigger proppant crushing or the flowback of proppant, resulting in fracture closure and loss of production. In frac packs and high-rate water packs, an abrupt increase in the rate (or drawdown) may induce completion damage, resulting in impaired production and sand production and requiring excessive and costly workovers. Choke-management strategies should aim to minimize near-wellbore pressure gradients along the fracture, thus making proppant flowback and loss of fracture conductivity or connectivity with the wellbore less likely to occur. Choke-management strategies are compared for a wide range of formation and fracture properties, including fluid properties, matrix permeability, fracture conductivity, and fracture length. Results indicate that in unconventional formations (kโ<โ0.01 md) there is a unique choke-management strategy that consistently appears to be the best. The methodology is coupled with previous studies that have focused on determining the critical pressure gradient for which proppant flowback is observed. In frac packs and high-rate water packs, completion failure may occur because of excessive fluid velocities along the frac pack or exaggerated pore-pressure gradients at the completion sandface. Results indicate that the selection of the optimal choke-management strategy is similar to that of openhole completions, with beanup operations achieving a relatively higher reduction in pressure gradients for the case of low values of dimensionless fracture conductivity. The greatest reduction in pressure gradients can be achieved by considering beanup operations during completion design. The results of this study provide, for the first time, a clear methodology for selecting choke-management strategies in hydraulically fractured wells and frac-pack completions for a wide range of reservoir and fluid properties. A general framework for beanup operations is defined and then used to compare beanup strategies for hydraulically fractured and frac-pack completions. It is hoped that this paper will contribute a theoretical foundation to the current diverse operator practices.
- Europe (1.00)
- North America > United States > Texas (0.94)
- Research Report > New Finding (0.68)
- Personal (0.67)
- Well Completion > Sand Control > Frac and pack (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
Summary Horizontal-well developments, focused on transverse hydraulic-fracture stimulation, have evolved rapidly during the past decade. Many of these completions may have missed or bypassed significant reserves that were intended to be produced from the well. This paper discusses the potential reasons for these inefficient completions, candidate selection for refracturing, and the impacts of offset depletion/infill wells on refracturing. Rate-transient post-treatment stimulation analysis is a powerful tool that can help determine whether and when a horizontal well is receptive to refracturing. Such analysis can help determine whether a well is underperforming, and if that underperformance is caused by an inefficient completion or by reservoir conditions. The paper discusses the importance of appropriate well conditioning/unloading before determining if a refracturing may or may not be successful. The impacts of โbashingโ into offset depletion during refracturing treatments are also discussed, along with appropriate design considerations to minimize such impacts. Refracturing can be an important tool to the industry, and it deserves the attention that it is currently receiving. However, the success of such treatments is not guaranteed in every well, and the criteria for candidate selection should be a top focus when evaluating such a program.
Summary Wells with extended-reach multilaterals have improved reservoir contact and have opened the opportunity for well-placement and -drilling optimization. Since the early 2000s, the number of maximum-reservoir-contact wells has increased substantially, and the benefit of these wells is being realized at the early implementation stage. To enhance the performance of these multilateral wells, intervention operations in the laterals are required. Stimulation, data acquisition, and other operations are required to optimize the production from the laterals; however, accessing the lateral of any wellbore for intervention in a reliable manner is still a challenge. The present paper describes the development of an intelligent, real-time controllable tool, the well-lateral-intervention tool (WLIT), that can identify a lateral junction and steer an intervention/surveillance string into it. The WLIT is designed to be deployed by use of either coiled tubing or e-line (with the help of a well tractor for extended-reach horizontal deployment) for logging and/or stimulation purposes. This application provides the ability to increase the quantity and quality of information collected from the entire wellโmain bore and the multiple laterals individuallyโto obtain the best answer. The discussion is dedicated to the development stages of the tool and field-trial-test results. The WLIT has two versions. The first version is called โwired,โ which accommodates specific logging tools that are compatible with the WLIT design, whereas the second version, โwireless,โ allows the use of all types of logging-tool strings from any third-party provider. The test results highlight both versions of the tool. The WLIT sensory equipment and the control environment are described, and results from the field-trial tests are presented.
- Asia > Middle East > Saudi Arabia > Eastern Province (0.46)
- Asia > Middle East > UAE > Abu Dhabi Emirate (0.28)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Zakum Concession > Zakum Field > Upper Zakum Field > Thamama Group Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Rub' al Khali Governorate > Rub' al Khali Basin > Shaybah Field (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- (8 more...)
Summary Frac-pack techniques were used in a recent subsea well-completion campaign. The sandstone layers that were targeted for completion are present generally in shallow gas reservoirs, with depths ranging from 2,000- to 4,500-ft (609.60- to 1371.60-m) true vertical depth subsea, and exhibit a varying degree of consolidation. Core data show that deeper pay intervals predominantly comprise fine-grained, poorly consolidated sandstones with good porosity development and permeabilities in the range of 100 to more than 1,000 md. These sand layers are often separated by shales and claystones. In contrast, the targeted sandstone layers in shallower intervals consist mostly of more-consolidated rock, with lower permeabilities in the range of 5 to 50 md. Up to eight sand intervals are targeted in each well. The subsea environment posed a challenge for well-completion design because of the multilayered completion strategy that was required to drain several of the pay units effectively in each well. Multizone frac-pack completions consisting of isolation packers and sand-control screens with separate pumping and production sleeves were used to provide sand control. An inner string of additional isolation seals, gauges, and intelligent control valves was run to provide zone-specific monitoring and production control. The initial well-completion work resulted in high skin values during production. A review of the post-stimulation data helped to identify the shortcomings in the designs and completion procedures. As a result, changes were made in the completion procedures, and frac-pack designs were tailored to suit the purposes. When these changes were implemented in subsequent wells, an improvement in well performance was seen, mostly in the form of reduced skin. This paper details this evolution, including favorable modification of completion procedures and the changes in pump schedule, treatment planning, and delivery methods during the frac-pack campaign. The benefit of adopting such an approach through the use of the methods and techniques implemented in this campaign can be applied to similar fields under development.
- North America > United States > Texas (0.67)
- Asia (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.68)
- 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)
- (21 more...)