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Collaborating Authors
SPE Oklahoma City Oil and Gas Symposium
Abstract The effect of traditional chemical treatments at the pump intake can be minimized due to the fluid level, high GLR, and production packers, among other reasons. Using a slow-release polymer matrix is an effective chemical treatment that was installed in several wells in the Delaware basin with Conoco Phillips. The chemicals were encapsulated in the matrix ensuring maximum absorption and then slow dispersion, and the tool was run under the intake of rod pumps, ESPs, and gas lifts. In rod pumps, the installations were carried out by pulling the production tubing while in the Gas Lifts, the chemical tools were installed via slickline without pulling the BHA. In the gas lifts and rod pumps, the chemical tool can be replaced whenever the concentration levels reach the minimum effective concentration without pulling the tubing. To track the dispersion rate, the wells were sampled monthly to measure the concentration of scale and corrosion inhibitor and the amount of THPS downhole. The whole tracking history of the wells will offer valuable information about the chemical concentrations expected using downhole chemical treatment compared with the concentrations obtained while using surface treatments and the longevity of the treatment at the production rates and depths installed. Corrosion and scale are some of the major issues in the Conoco Phillips field in the Delaware Basin. after installing the downhole chemical treatment in different wells, the KPIs determine stable conditions downhole without failures reported. The manganese and iron concentration remained stable in the wells assessed, the chemicals concentration has been above the MEC (minimum effective concentration) and the wells are still running. The main impact of these favorable conditions is the run time and the fact the total cumulative production increased compared to the same period before the installation.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- 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)
- (26 more...)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas lift (1.00)
- Production and Well Operations > Artificial Lift Systems > Beam and related pumping techniques (1.00)
Abstract Primary barriers to fracturing the reservoir 24/7 have been identified as 1) the time between stages (this includes transition time and pressure tests), 2) downtime associated with gate valve maintenance and failures, 3) frac pump maintenance and 4) sand and water logistics. Following a prescribed roadmap, a system has been developed with new subsystems and processes to eliminate these identified barriers through novel products and automated workflows resulting in fracturing the reservoir more hours per day with the goal of reaching 24 hours a day, 7 days a week (please note the difference between being on a frac site 24/7, which occurs today, and fracturing the reservoir 24/7). The system eliminates the time between stages with rapid, automated transitions from one stage to the next enabling operators to continuously pump for the duration of the completion. Utilizing automated workflows, interlocks with wireline and frac systems, control systems, and RFID, the system eliminates NPT associated with stage-to-stage transitions. An addition to the system that enables the exchange of pumps during frac operations without stopping the frac has gone through initial field trials, with a second iteration soon to be deployed. Although the overall system does not directly solve logistic issues (i.e. sand and water shortages), the demonstrated consistency achieved using the system enables better planning of resources. A summary of the system’s accomplishments, some previously disclosed, some new, will be presented. The system has broken multiple pumping records across US basins including hours pumped continuously and stages completed. In addition, the system has over a dozen industry "firsts" that have advanced completion practices, reduced NPT, and eliminated transition time. The paper highlights new additions to the system including the automated lubricator, automated greasing algorithms, and the ability to exchange a pump truck while fracturing. Utilizing the plentiful data provided by the system, specific case histories are documented highlighting the gains in operational efficiency, consistency and safety resulting from the new system.
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
Abstract An oil well in Ohio in the process of being decommissioned had pressure on the 13-3/8" × 9-5/8" annulus. Ohio Department of Natural Resources (ODNR) regulations require gas flow be eliminated prior to abandonment, prompting remediation. Several cement plugs had already been set in the well, preventing access for a traditional perf and squeeze technique to treat the leak without drilling out the plugs. A biomineralization company was contracted by an operator in Ohio to apply their proprietary biomineralization technology to seal leakage pathways in the cemented annulus via direct injection into the annulus at surface. The operator prepared the well for surface injection by adding lines and valves to the 13-3/8" × 9-5/8" annulus to allow for pumping in the inlet and out the outlet. Biomineralizing fluids were then pumped into the well, where they formed crystalline calcium carbonate in the micro annuli. Thirty-six hours after the start of treatment, the injection rate had dropped by several orders of magnitude. Subsequent monitoring by a ODNR personnel determined gas flow had been eliminated and the well was approved for permanent abandonment.
Abstract Narrow pore/stability pressure and fracture pressure margins (narrow operating window) can create severe complications during drilling operations. A slight change in the bottom hole pressure conditions can lead to significant Non-Productive Time (NPT) events like stuck pipe, fluid influx or lost circulation. In many cases, long wells with a narrow gap between pore/stability pressure and fracture pressure are impossible to drill with conventional practices because the annular friction pressure losses (difference between the dynamic and static pressure) are larger than the pore/fracture margin (Arnone & Vieira, 2009). Managed Pressure Drilling (MPD) enables operators to carefully balance between the pore and fracture pressure gradient by counteracting the lack of annular pressure losses (APL) when not circulating with the application of surface back pressure (SBP). MPD has the capability of providing a nearly constant bottomhole pressure with the proper compensation of pressure changes at surface. An accurate and real time determination of change in bottom hole pressure from dynamic effects is necessary to apply the correct SBP. This work investigates the accuracy of a novel approach in real-time MPD hydraulics modelling, which provides an alternative solution to the Pressure-While-Drilling (PWD) tool that measures the downhole annular pressure while drilling. The real-time hydraulics modelling proved to be accurate and allow for adjustments to be continuously made towards optimizing drilling efficiency, reliability, and safety without additional downhole tools.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (0.72)
- 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)
- (28 more...)
Abstract The miscible gas injection has been a successful technique to overcome the low oil recovery by improving the oil mobility due to viscosity reduction. While many experimental studies defined the fundamentals of gas injection in heavy oil reservoirs, experimental studies of gas injection into condensate oil reservoirs are scarce. Therefore, this study provides a comprehensive investigation of the impact of the injection pressure and reservoir permeability on the efficiency of CO2 to improve oil recovery from oil condensate reservoirs. The efficiency of the injected gas at different injection pressure into different permeability rocks is evaluated as a function of the recovery factor and the viscosity reduction experimentally. Miscible gas injection experiments of different shale rock samples with different permeabilities saturated with condensate oil were conducted at 5 different injection pressures. The recovery factor will be used to investigate the effect of injection pressure in two distinctly saturated rock samples. These samples are saturated with condensate oil from the Eagle Ford formation. The Minimum Miscible Pressure is predicted from the compositions of the fluids, which is determined using gas chromatography. The gas is injected at different pressures, and the recovery factor is calculated at the gas breakthrough, the end of the injection (Injecting 3 PV), and at the abandonment pressure (100 psi). The viscosity of the collected oil at the end of each run is measured to determine the viscosity reduction value. The experimental results proved the success of CO2 injection in improving condensate oil production. A proportional relationship between the injection pressure and the recovery factor was observed. Moreover, a proportional relation was observed between the production and the permeability. However, the permeability and the viscosity reduction were observed to be inversely proportional. This observation was extended to the immiscible injection, where the oil viscosity was reduced by a small percentage. This reduction is translated to an existence of some level of miscibility within the pores of the lower permeability sample. This phenomenon could be caused due to the higher nanopore confinement pressure in the lower permeability samples.
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.82)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
Introducing Digitalization and Automation for Improvements in Fracturing Operational Efficiency and Safety
Ortiz, Camila (SLB, ORCID 0000-0002-5879-3678) | Taitt, Graham (SLB, ORCID 0000-0001-5381-5076) | Balzan, Angel (SLB, ORCID 0000-0002-1280-0510) | Viator, Tony (SLB, ORCID 0000-0001-9770-8141) | Fux Campa, Ramiro (SLB, ORCID 0000-0003-4015-6352)
Abstract Attaining peak efficiency in zipper fracturing operations is an important objective for oil and gas companies. More-complex operations result in greater efficiency but also demand the use of digitalization to maximize safety and performance. A digital technology using industrial Internet of things (IIoT) edge computing and cloud analytics for the automation and control of frac valves is presented. It enables operators to deliver more fracturing stages with less nonproductive time (NPT) while enhancing visibility, safety, and integrity. The digital solution integrates supervisory applications, control systems with programmable logic controllers (PLCs), networking devices, instrumentation, digitally enabled skids, and cloud solutions. The system uses an edge application that provides the ability to monitor valve status, control valve actuation, and automate valve greasing, using customizable software workflows and safety controls and alerts following standards managing wellsite safety. It eliminates valve operational errors using enforced workflows and interlocks based on operational awareness and instrumentation. The unintentional cutting of wireline (WL) has effectively been eliminated through the use of a proprietary detection algorithm that uses input from nonintrusive and intrinsically safe sensors in real time. Pumping detection algorithms eliminate human error and prevent the overpressurization of valves using interlocks embedded in the software. Using digitally enabled controls that streamline frac tree and manifold valve operations, operators can reduce safety risks by reducing the headcount on location and eliminating red-zone activities; operational integrity is secured by enforcing the digital handshake and providing isolation valve interlocks between the well stimulation and well control equipment to prevent overpressurizing or washing out the frac valves. By integrating complex new workflows and flow control technology with digital controls, transition times are shortened, enabling maximum pumping time per day. The operational integrity provided by the embedded safety interlocks empowers operators to operate efficiently and without worrying about safety. The system uses a design language system-type web application, which has proven to be effective, consistent, and intuitive. Using ruggedized tablets and operating 100% remotely, the field technicians have found the system to be easy to understand and operate. The edge application has completed more than 10,872 stages in more than 258 wells, and data has been collected that verifies that the cost of ownership has been reduced by double digits. The number of completed fracturing stages in a day has increased by 50%, the transition (non pumping) time has been reduced by 41%, and valves are being greased outside of the critical path. The presence of personnel in the red zone has been eliminated, and only one service technician is required to operate the valves and perform maintenance. Using edge computing processing and analyzing data at the source (the frac pad), workflows that traditionally have been operated manually and were prone to human error have been digitalized and streamlined. Moreover, having the data sent to a cloud portal enables insights to be extracted, providing more-detailed information regarding the performances of the equipment and personnel, which helps monitor the health of the frac valve fleet and produces predictive maintenance plans, leading to reduced repair and failure costs.
- Information Technology > Cloud Computing (1.00)
- Information Technology > Architecture > Real Time Systems (0.36)
Application of Machine Learning Optimization Workflow to Improve Oil Recovery
Koray, Abdul-Muaizz (New Mexico Institute of Mining and Technology) | Bui, Dung (New Mexico Institute of Mining and Technology) | Ampomah, William (New Mexico Institute of Mining and Technology) | Appiah Kubi, Emmanuel (New Mexico Institute of Mining and Technology) | Klumpenhower, Joshua (New Mexico Institute of Mining and Technology)
Abstract Machine learning application in the oil and gas industry is rapidly becoming popular and in recent years has been applied in the optimization of production for various reservoirs. The objective of this paper is to evaluate the efficacy of advanced machine learning algorithms in reservoir production optimization. A 3-D geological model was constructed based on permeability calculated using a machine learning technique which involved different architectures of algorithms tested using a 5-fold cross-validation to decide the best machine learning algorithm. Sensitivity analysis and a subsequent history matching were conducted using a machine learning workflow. The aquifer properties, permeability heterogeneity in different directions and relative permeability were the control variables assessed. Field development scenarios were exploited with the objective to optimize cumulative oil recovery. The impact of using a normal depletion plan to a secondary recovery plan using waterflooding was investigated. Different injection well placement locations, well patterns as well as the possibility of converting existing oil producing wells to water injection wells were exploited. Considering the outcome of an economic analysis, the optimum development strategy was realized as an outcome for the optimization process. Prior to forecasting cumulative oil production using artificial neural network (ANN) for the optimization process on the generated surrogate model, a sensitivity analysis was performed where the well location, injection rates and bottomhole pressure of both the producer and injector wells were specified as control variables. The water cut as part of the optimization process was utilized as a secondary constraint. Forecasting was performed for a 15-year period. The history-matching results from the constructed geological model showed that the oil rate, water rate, bottom hole pressure, and average reservoir pressure were matched within a 10% deviation from the observed data. In this study, the ANN optimizer was found to provide the best results for the field cumulative oil production. Using a secondary recovery development plan was observed to significantly increase the cumulative oil production. A machine learning based proxy model was built for the prediction of cumulative oil production to reduce computational time. In this study, we propose an approach applied to reservoir production optimization utilizing a machine learning workflow. This was accomplished by utilizing a surrogate model which was calibrated with a number of training simulations and then optimized using advanced machine learning algorithms. A detailed economic analysis was also conducted showing the impact of a variety of field development strategies.
- North America > United States > Texas (1.00)
- North America > Canada (0.69)
- Asia (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.67)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Farnsworth Field (0.99)
- North America > United States > Texas > Anadarko Basin (0.99)
- (9 more...)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Optimization (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Neural Networks (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Clustering (0.47)
Abstract Geothermal energy has vast potential as a reliable energy source of the future. However, its development has mostly been tied to specific geological locations or igneous rocks. Even though most western US regions have high thermal gradients compared to other places, higher temperatures are easily achievable by increasing the total depth in sedimentary rocks. The oil and gas industry has successfully mastered drilling sedimentary basins cost-effectively. Comparing cost/ft from typical sedimentary basins to granite or igneous rocks shows a tremendous difference. In addition, recent hydraulic fracturing technology transfer from the oil and gas industry can be deployed for geothermal applications. A potential new path toward expanded geothermal energy production is to use known porous and permeable reservoir rocks in appropriate sedimentary basins, where those formations have a sufficient temperature, thickness, porosity, and permeability, existing at depths that drilling time makes well construction costs economical for geothermal applications. In this paper, we will examine the unique potentials that sedimentary basins in Oklahoma offer to the geothermal industry for different end-user purposes, such as electricity generation or direct heat applications. The state has high geothermal gradients in some regions in the Arkoma Anadarko Basins that could be used for medium-temperature resources. Case studies from Oklahoma show how the many oil and gas wells in the state can enable geothermal direct-use projects. A state-wide levelized cost of energy analysis using geothermal gradient data indicates that there are areas with the potential to produce geothermal power at 14 cents/kWh or less. Geothermal energy has the potential to play a crucial role in Oklahoma's energy supply by offering a clean and renewable source of power that can fulfill energy demands.
- Geology > Rock Type > Igneous Rock (1.00)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.46)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.46)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Renewable > Geothermal (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Gulf of Mexico > Gulf Coast Basin (0.99)
- North America > United States > Texas > Meramec Formation > Meramec Formation > Mississippi Chat > Mississippi Lime > St. Louis Formation (0.94)
- North America > United States > Texas > Meramec Formation > Meramec Formation > Mississippi Chat > Meramec Formation > St. Louis Formation (0.94)
- (32 more...)
Abstract As more and more water is being co-produced with hydrocarbon, saltwater management has become an important enterprise. Out of many available tools in water management, saltwater disposal through Type II wells is critical to handling large quantities of produced brine. Since the produced water usually contains impurities such as solids, oil and grease, and bacteria, the well's injectivity deteriorates over time as the skin factor develops. Injecting over the formation parting pressure (FPP) gradient may lead to a matrix bypass event and other geohazards; accurately determining the FPP of the target formation is needed to maintain safe injection operations. However, using the step rate test (SRT) doesn't warrant an accurate result. As the target formations can have multilayers with distinct properties, we often find that SRT is often misused. SRT is often recommended based on oil field operational experience because it is easy to execute and interpret. One fundamental assumption for SRT is that the target formation is a single layer with relative isotropic properties; however, this isn't always true for saltwater disposal wells (SWDs), which usually penetrate through multilayers with very heterogeneous properties. To illustrate our concept, we present a case study using SRT results from an active SWD well located in the Anadarko Basin. We recommend a geomechanical model to determine the operating surface pressure in this paper. The geomechanical model considers the original stresses, variation of geomechanical parameters, injection pressure, and temperature. To consider the uncertainties of these parameters, we demonstrate how to use Monte Carlo simulation to determine the maximum operating surface pressure. We recommend several analyses for the collected data to determine the well's injectivity variation. The Monte Carlo simulation result yields a possible fracturing gradient and presents the probability of each fracturing gradient. Probability is crucial in decision-making as different operators/fields may have different risks, tolerance, and uncertainties. The recommended practice is an integration of data sets and analysis that yield the maximum injection pressure to maintain the well and formation integrity with different risk tolerance levels.
- North America > United States > Texas > Kleberg County (0.24)
- North America > United States > Texas > Chambers County (0.24)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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...)
Abstract Unconventional field production relies heavily on artificial lift, but with reservoir energy depleting, lifting hydrocarbons efficiently and economically is one of the challenging parts of field development. Traditional lift selection methods are insufficient for managing unconventional wells with high initial decline rates. Understanding how production behaves under various lift conditions is crucial because lift method timing and design are the most important considerations for optimizing well performance. In order to increase the value of unconventional oil and gas assets, this paper presents an artificial-lift timing and selection (ALTS) methodology that is based on a hybrid data-driven and physics-based workflow. Our formulation employs a reduced physics model that is based on identification of Dynamic Drainage Volume (DDV) using commonly measured data (flowback, daily production rates, and wellhead pressure) to calculate reservoir pressure depletion, transient productivity index (PI) and dynamic inflow performance relationship (IPR). Transient PI as the forecasting variable normalizes both surface pressure effects and takes phase behavior into account, reducing noise. For any bottom hole pressure condition, the PI-based forecasting method is used to predict future IPRs and, as a result, oil, water, and gas rates. The workflow calculates well deliverability under various artificial lift types and design parameters. The ALTS workflow was applied to real-world field cases involving wells flowing under various operating conditions to determine the best strategy for producing the well among several candidate scenarios. The results of transient PI and dynamic IPR provided valuable insights into how and when to select different AL systems. The workflow is run on a regular basis with ever-changing subsurface and wellbore conditions against each candidate scenario using different pump models and other operating parameters (pressure, speed etc.). The method was applied in hindcasting mode to several wells to evaluate lost production opportunity and validate the results. In some cases, the best recommendation was to use a different artificial lift system than the one used in the field to significantly improve long-term well performance. Furthermore, optimal artificial lift operating point recommendations for wells are made, including optimal gas lift rates for gas lifted wells, optimal pump unit selection and speed for ESP and SRP wells. The proposed method predicts future unconventional reservoir IPR consistently and allows for continuous evaluation of artificial lift timing and selection scenarios in unconventional reservoirs with multiple lift types and designs. This has the potential to shift incumbent practices based on broad field heuristics, which are frequently ad hoc, inefficient, and manually intensive, toward well-specific ALTS analysis to improve field economics. Continuous use of this process has been shown to improve production, reduce deferred production, and extend the life of lift equipment.
- North America > United States > Texas (0.29)
- North America > United States > Mississippi > Marion County (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- (2 more...)