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Surface-Controlled Digital Intelligent Gas Lift Valve Technology Deployed in North American Unconventional Producing Wells. Lessons Learned After Field Trials and the Path Ahead
Suarez, S. A. (Silverwell Technologies Inc, Houston, TX, USA) | Shaw, J. (Silverwell Technologies Inc, Houston, TX, USA) | Bastardo, R. (Silverwell Technologies Inc, Houston, TX, USA) | Patterson, G. (Silverwell Technologies Inc, Houston, TX, USA)
Abstract Objectives/Scope Several wells have now recently been completed with a novel digital intelligent surface-controlled gas lift technology with the goal of assessing their performance and their feasibility as an artificial lift solution for producing unconventional wells. These installs mark the first ever successful installations of this technology in North America land. As of recent years, gas lift has started to gain ground as the artificial lift option of choice for the operators in many Unconventional basins and the goal of this research aims to provide the complete details of the lessons learned during these projects and lay the ground for scaling-up in the near future. Methods, Procedures, Process The research followed closely actual field trial installations of Surface-controlled intelligent gas lift systems that were installed in the Bakken and Permian Basins with the premise of testing its performance prior to larger deployments. The totality of the field trials featured multiple digital intelligent gas lift mandrels that carry pressure and temperature gauges and electrical-actuated valves controlled from surface through a tubing encapsulated line. This can ensure that the optimum gas injection rate can be selected to achieve the maximum production throughout the life of the well over time as Bottom Hole Pressure declines, without the need for wireline intervention to change out a valve, which is required with conventional gas lift. Tailored well designs applications were done to each well candidate with the purpose to evaluate their behavior and agreed-upon KPI's during the trial period. A project closing document was produced for each well which details all the learnings the team was able to gather from real life testing and experience. Results, Observations, Conclusions In these applications, the surface-controlled intelligent gas lift system presents an opportunity for a data driven approach to ensure the optimum gas injection rate is achieved through surface operation and downhole multi-port functionality. While paving the way to other areas where the concept could prove useful as well. We present field unloading procedures, optimization options and well performance enhancements with the newly available data that was able to be gathered. Operational and design improvements were successfully implemented by the team and the operator from the documented lessons. Novel/Additive Information First wells successfully installed in the Unconventional plays in the US, proving that the technology can become a nice fit in the operator's toolbox when dealing with rapid changing conditions and steep declines in production rates coupled with higher Gas Liquid Ratios such as unconventional reservoirs.
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (27 more...)
Abstract Búzios is the largest ultra-deep water oil field in the world, located on the Brazilian coast, in the pre-salt polygon. Its development has taken place at an accelerated pace, with more than 60 wells already drilled and 4 FPSO's operating by the end of 2022, and a forecast of 7 more installed up to 2026, and at least 80 more wells till 2030. In this way, well configurations represent a great challenge, requiring technological and technical developments to allow high production flow and maintenance of integrity throughout the field's productive life, estimated in 30 years. Several well configurations, whether in drilling or in completion, were applied with greater or lesser success, bringing objective results in the reduction of time in well construction: from 130 days at the beginning of development to durations of less than 80 days, reducing CAPEX and increasing the rate of return on investment. This work aims to describe the various challenges faced in the design of well projects and construction, whether in drilling or completion, as well as how the geological characteristics of the field influenced the choices and methodologies adopted. In addition, demonstrate how the methodologies contributed to improve the quality of construction and linked to the reduction of time and costs.
- South America > Brazil (1.00)
- North America > United States > Louisiana (0.41)
- Geology > Structural Geology > Tectonics > Salt Tectonics (1.00)
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Mineral (1.00)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Marambaia Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Block BM-S-11 > Buzios Field > Guaratiba Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Ariri Formation (0.99)
- (3 more...)
A Set of Options for Stimulation of Wells
Isaev, Anatoliy Andreevich (Sheshmaoil Management company LLC) | Takhautdinov, Rustem Shafagatovich (Sheshmaoil Management company LLC) | Malykhin, Vladimir Ivanovich (Sheshmaoil Management company LLC) | Sharifullin, Almaz Amirzyanovich (Sheshmaoil Management company LLC) | Aliev, Mekhrali Mirzaliogly (Almetyevsk State Oil Institute)
Abstract The most effective well interventions employed by Shehsmaoil Management Company LLC (Republic of Tatarstan, Russia) are the following [1-4]: –hydraulic fracturing (HF), –forced gas extraction unit from a wellbore annulus. The article addresses the issues of increasing recoverable reserves of oil, oil recovery factor, speeding up development, improving the profitability of deposits and fields (with carbonate deposits) as a whole through the introduction of proppant fracturing technology (PHF), multistage fracturing in wells with horizontal endings, drilling a compact grid of wells with subsequent fracturing. It is indicated that optimization of PHF (transition to hybrid hydraulic fracturing) by combining low-viscosity and cross-linked fluids depending on the performance during test injections made it possible to stabilize product's water cut, increase well productivity in terms of oil and stabilize oil recovery reduction rate. All relevant operations are implemented by three functioning hydraulic fracturing fleets operated that uses the equipment mounted on all-terrain chassis. The paper reviews and summarizes the application results of various fracturing fluid systems: borate-crosslinked guar fluids, Bioxan modified natural polysaccharide, fluids based on fresh water or viscoelastic surfactants, guar-free low-viscosity and high-viscosity water-based polymer systems, synthetic gelling agent. All the described systems feature the required sand trapping properties, so it is the price of the systems that determines the best choice. The article considers a portable set of equipment for forced extraction of gas from the wellbore annulus and its subsequent pumping into the oil pipeline by means of gas extraction sets of the KOGS type. In the conditions of shallow fields with hard-to-recover reserves the Company specialists encounter the challenge of increasing the profitability of development. The main reserves of the fields under consideration are confined to carbonate targets, and the reserves of deposits of the Kizelovsky gorizont of the Tournaisian stage occupy a considerable place by their quantity. Development of this object is mainly complicated by the following factors: complex geological structure, viscous, heavy and resinous oil, low reservoir temperatures and pressures. For the reasons of low efficiency of classical development systems, systems of reservoir pressure increase, it is necessary to develop, test, introduce new methods of intensification, new elements of development - compaction of well grid, horizontal wells (HW) with the following multistage fracturing. The fields considered in the article are tectonically controlled by the Western slope of South Tatar arch and Eastern edge of Melekesskaya depression, territorially located in Tatarstan.
Abstract Carbon dioxide (CO2) is commonly used for enhanced oil recovery (EOR) in the Permian Basin and is gaining interest for Carbon Capture, Utilization & Storage. A study was conducted to develop candidate selection criteria, pilot test the design, and optimize CO2 gas lift to stabilize production on intermittently flowing wells in one of these EOR fields. The initial CO2 gas lift design was installed in 2019 using a capillary string, downhole check valve, gas lift mandrel, and packer. A 34-day bottomhole pressure and temperature survey was evaluated to assess the success of the pilot and improve the equipment design for future installations. The phase changes of CO2 were accounted for when evaluating the pilot, modeling gas lift, and improving equipment design. Carbon dioxide is a complex fluid at the bottomhole pressures (BHP) and temperatures (BHT) observed during the pilot. These pressures and temperatures were plotted on the CO2 phase diagram, which showed phase changes between vapor and liquid at higher gas lift injection rates. Further analysis revealed the CO2 changed phase from a liquid to a vapor across the downhole check valve. The Joule-Thompson (JT) effect across the check valve at the tubing entry point dropped the temperature of the produced fluids so much that the CO2 changed phase from a vapor back to a liquid. This increased the hydrostatic pressure and therefore, the bottomhole flowing pressure. These CO2 phase changes in the tubing occurred in cycles comprising five distinct stages: (1) BHT cooling forced CO2 from the vapor to liquid phase and increased BHP; (2) BHT remained fairly steady as BHP increased due to liquid loading; (3) BHT started warming at a faster rate as BHP rose due to the decreasing pressure drop across the downhole check valve; (4) the tubing unloaded as CO2 flashed in a chain reaction down the tubing, resulting in an influx of warmer reservoir fluid; and (5) BHT remained steady as BHP decreased and the annular packer fluid restarted the cooling process. Results from this initial pilot were used successfully to optimize CO2 gas lift for subsequent installations. CO2 gas lift can be an effective artificial lift method to stabilize production if the equipment is designed correctly to maximize the CO2 gas fraction at the tubing entry point. A poorly designed CO2 gas lift installation may result in unstable production from liquid loading events caused by the cyclic JT effect. CO2 gas lift is a valuable artificial lift method to reduce failure frequency and operating costs in EOR fields with readily available CO2.
- 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)
- (23 more...)
Automated ESP-Lifted Well Startup Using Model Predictive Control: Introduction of the Algorithm and Field Tests Results
Sadowska, Anna (Schlumberger) | Steenson, Leo (Schlumberger) | Williams, Michael (Schlumberger) | Meredith, Andrew (Schlumberger) | Chong, Jonathan (Sensia Global) | Anderson, Jeffery (Sensia Global) | Kelly, Dwayne (Sensia Global)
Abstract The start of an electric submersible pump (ESP) is the most dynamic event in the life of the ESP, and one that has been shown to be the main contributor to the premature failure of the ESP; yet it is clearly unavoidable. This article introduces an algorithm comprising of a model-predictive controller and a moving horizon estimator for automating the well startup. Objectives and constraints related to the startup are considered for the whole well system, including the reservoir, the ESP, the tubing etc. A lumped-parameter model is established to model the fluid dynamics in the system. The estimator recalibrates the model and provides estimates (virtual measurements) in lieu of unavailable physical measurements. The operating sequences for the ESP and choke are then updated step-by-step by the controller, considering the model of the system, the startup objectives and constraints, and the measured feedback information from the wellbore gauges. The startup algorithm was implemented on a field edge device and deployed to a well in the Permian Basin. The algorithm executed two successful startups. A model recalibration was conducted before the second startup which improved the accuracy of setpoint tracking.
- North America > United States > Texas (0.34)
- North America > United States > New Mexico (0.24)
- 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...)
In 2014, a research and development (R&D) project was initiated to increase the life expectancy of Gulf of Mexico (GOM) Miocene and Lower Tertiary water-injection (WI) wells, several of which had suffered a severe loss of injectivity within only a few years of completion. The solution was to find a way to prevent fine material from entering the completion while sustaining high injection rates, with no loss of injection pressure or requirement for additional horsepower. A new flow-control device (FCD) and completion system were developed along with intrinsic nonreturn valves (NRVs) that prevent any backflow or crossflow during shut‑ins. Tubing-deployed injection valves and regulators have been available for many years. However, these cannot address the problem of annular flow.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.50)
Abstract We present a review of new gas lift technologies designed to deliver increased production rates when compared to conventional gas lift systems and demonstrate the applicability of these systems in unconventional development wells in the Permian Basin. We focus on results from wells employing electrically operated downhole injection technologies that provide a deeper point of injection and conserve surface injection pressure, reducing flowing bottom hole pressure. We present wells that represent a range of the inflow performance spectrum in the Permian Basin. These wells were completed with remotely operable injection stations to understand the impact of a variety of flowing conditions. Several Gas Lift indicators are used for efficiency evaluation criteria: Depth of injection, multi-pointing elimination or reduction, and properly-sizing injection port to enable gas injection at critical flow. Downhole and surface conditions were continuously and remotely monitored, and included pressure and temperature sensors at each station, both inside and outside of tubing. We present results that: enabled tuning of annulus pressure calculations; provided reliable gas lift modelling and optimization when compared conventionally equipped gas lift wells; demonstrated the benefits of preserving Gas Lift pressure for single point of injection as deep as possible. These results delivered performance increase, reduced uncertainty in diagnostics and well performance analysis and enhanced completion designs that included the remote operated valves. In all situations the depth of injection was moved further down the well, eliminating multipoint injection observed in conventional gas lift equipment. Currently, there are several electrically operated gas lift valves available on the market with similar capabilities but vary in design and implementation. Ongoing evaluation of these technologies enable maturation of this technology and creates the opportunity to combine it with integrated production optimization and autonomous operations in the future.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.81)
- 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...)
Long Term, Periodic Aerial Surveys Cost Effectively Mitigate Methane Emissions
Sridharan, Sri (Pioneer Natural Resources) | Lazarus, Aaron (Pioneer Natural Resources) | Reese, Carrie (Pioneer Natural Resources) | Wetherley, Erin (Kairos Aerospace) | Bushko, Katrina (Kairos Aerospace) | Berman, Elena (Kairos Aerospace)
Abstract Results of multiple years of periodic aerial methane surveys over Pioneer Natural Resources’ operations footprint, comprising approximately 680,000 acres in the Permian basin, are presented, including impacts to operational efficiency, cost, and methane emissions mitigation. Aerial methane detection was performed using a light-aircraft mounted, integrated methane imaging spectrometer. Geo-referenced methane emissions data combined with real-time geo-referenced optical imagery provided accurate methane localization and source attribution. Ground inspection teams used optical gas imaging technology to validate the aerial results and dispatch repair teams. Externally validated leak quantification provided by the spectrometer further allowed accurate measurement of methane mitigation. Aerial methane inspections of nearly 10,000 operations sites per survey, including wells, tank batteries, and all associated equipment, are reported for multiple years of periodic surveys. The data shows a complete picture of the most significant methane emissions from the Pioneer operations footprint over consecutive years and has proven beneficialinvaluable for enhancing operational efficiency. Based on the data, Pioneer has been able to identify the areas of highest impact and focus operational resources on those improvements. Surveys identified types of emission sources that can be addressed immediately within Pioneer operations and areas where Pioneer would need to work with others to improve overall gas takeaway challenges in the Permian basin. Furthermore, Pioneer has reduced leak detection and repair (LDAR) costs significantly by reducing both driving time and ground-based inspection time. We estimate more than 2500 work hours and 1000 driving hours, were saved by each aerial survey. Between 2016 and 2018, the company's methane intensity has declined approximately 41%. Aerial survey results have allowed Pioneer to significantly reduce methane emissions while simultaneously improving safety and efficiency, reducing costs, and reducing vehicle traffic. To our knowledge, this is the first multi-year, comprehensive, aerial periodic methane survey of an entire upstream oil and gas operation's footprint. We're now able to report on the benefits of this paradigm shift away from conventional LDAR surveys. Although the challenge of reducing methane emissions can be daunting, the results from aerial monitoring show that with a technology and data-driven approach, operators can significantly reduce emissions while simultaneously reducing costs and improving operational efficiency.
- North America > United States > Texas (0.45)
- North America > United States > New Mexico (0.45)
- North America > United States > California > Los Angeles Basin (0.99)
- North America > United States > California > San Joaquin Basin > Pioneer Field (0.97)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.90)
- (23 more...)
An Efficient Downhole Oil/Water-Separation System with Sucker-Rod Pump
Jiang, Minzheng (Northeast Petroleum University) | Cheng, Tiancai (Northeast Petroleum University) | Dong, Kangxing (Northeast Petroleum University) | Liu, Jintang (Daqing Oilfield Company) | Zhang, Huaiyu (Daqing Oilfield Company)
Summary At present, many oil fields in China have entered the high‐water‐cut production period, and the water cut of oil wells has continued to rise. Therefore, how to reduce the water cut of the produced liquid, reduce the amount of surface water treatment, shorten the ineffective water circulation, and reduce the comprehensive production cost have become the key problems restricting the sustainable economic exploitation of a high‐water‐cut oil field. To this end, the development model of circular displacement and the oil‐recovery technology of a downhole oil/water‐separation system with sucker‐rod pump (DOWS‐SRP) are proposed. The technology system consists of downhole oil/water‐separation devices, an injection/production pump‐string system, a sealing system, and downhole data‐test system, mainly applied to separating the oil and water in the well through the separation device. The separated water is then directly injected into the formation and the separated concentrated liquid is lifted to the ground so the water injection and oil recovery are completed simultaneously in the same wellbore. The field‐test data show that after the implementation of injection/production technology in the same well, the surface liquid‐production volume decreased by 90%, the water‐cut decreased by 27%, and the water/oil ratio decreased by 93%. In addition, the liquid volume of lifting, gathering, and treatment was greatly reduced, as well as the surface infrastructure investment, to achieve the purposes of cost saving, energy saving, and consumption reduction. At the same time, the downhole reinjection replaces surface water injection, transforming ineffective surface water circulation into effective internal displacement power in the reservoir and improving the yield and recovery rate. The successful application of the quaternary‐oil‐recovery block has made it possible to redevelop a large number of abandoned oil reservoirs, providing a potential basis for quaternary oil production. In addition, the preliminary energy‐saving effect and economic‐benefit analysis are performed. The data show that the energy‐saving effect of this technology is obvious and good economic benefit is obtained.
- Asia > China (1.00)
- North America > United States > Texas (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.69)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.48)
- North America > United States > Louisiana > Alliance Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Liaoning > Bohai Basin > Liaohe Basin > Liaohe Field (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
- Production and Well Operations > Artificial Lift Systems > Beam and related pumping techniques (1.00)
- (2 more...)
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 192840, “Field-Trial Results for New Sand-Control Technology for Water Injectors,” by Steven Fipke, SPE, Tendeka; J.E. Charles, SPE, Shell; and Annabel Green, Tendeka, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed. In 2014, a research and development (R&D) project was initiated to increase the life expectancy of Gulf of Mexico (GOM) Miocene and Lower Tertiary water-injection (WI) wells, several of which had suffered a severe loss of injectivity within only a few years of completion. The solution was to find a way to prevent fine material from entering the completion while sustaining high injection rates, with no loss of injection pressure or requirement for additional horsepower. A new flow-control device (FCD) and completion system were developed along with intrinsic nonreturn valves (NRVs) that prevent any backflow or crossflow during•shut-ins. Developing the Flow-Control Technology Tubing-deployed injection valves and regulators have been available for many years. However, these cannot address the problem of annular flow. The most-damaging factor in solids production is likely crossflow, wherein differently pressured injection zones can flow between layers inside the tubing or casing annulus. Crossflow can be eliminated only by blocking the flow at the sandface. This solution also would mitigate the damaging effects of water hammer by blocking pressure waves from entering the lower completion. Check-valve components must fit within sand-control screens or be deployed across multiple zones of the injection tubing.• During the R&D phase of the project, researchers used extensive laboratory testing, flow-loop testing, and computational-fluid-dynamics modeling to develop a series of NRV prototypes. The technology was designed to handle a variety of well conditions, including erosion, plugging, temperature, and repeated checking cycles. All FCD components, including the NRV technology, are manufactured with high-alloy stainless steel and tungsten-carbide components to resist tortuous downhole conditions for up to 15 years. FCD prototypes and design iterations were tested over 18 months and a final design was qualified to withstand repetitive pressure- checking cycles reliably at 1,500 psi (and up to 10,000-psi static differential•pressure).• The laboratory testing conducted to finalize the project development stage is described in detail in the complete paper; it consisted of leak-rate, erosion, plugging, and screen-construction stages. One determination of this testing was that the placement of the screen over the FCD joint could cause erosive wear because of the placement of the screen ribs over the valves. An alternative rib wire was designed that could place the FCD between wires without compromising the strength of the screen. With laboratory and workshop testing completed by early 2017, the focus of the project shifted to identifying and organizing a field trial for the new technology in a low-cost, low-risk environment.
- North America > United States (0.67)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.45)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.49)