Yang, Junjie (Baker Hughes, a GE Company) | Karam, Pierre (Baker Hughes, a GE Company) | Cozyris, Kristian (Baker Hughes, a GE Company) | Hustak, Crystal (Baker Hughes, a GE Company) | Doherty, James (Riley Exploration – Permian, LLC) | Allen, Carmen (Riley Exploration – Permian, LLC)
As a well-known tight oil dolomite reservoir in Texas, San Andres formation has attracted broad attention about horizontal drilling and development strategy. To optimize the oil recovery and asset’s economics, the aim of the study was to use an integrated approach to understand reservoir heterogeneity and performance, determine optimal landing zone and its impact on production, understand fracture geometry using different pumping schedules, and the optimal cluster spacing. In addition, the potential benefit of a refrac and infill drilling program was also investigated.
To tackle the optimization problem, an integrated reservoir modeling workflow was developed. Starting with a 1-D geomechanical model which captures the in situ stress profile and rock mechanics, hydraulic fracture modeling was developed to history match the treatment process, and therefore a comprehensive fracture geometry can be estimated. In the interim, a geological model with populated reservoir properties was established based on the offset data including petrophysical logs, imaging logs and cores. After calibration, the dynamic reservoir model was built to test multiple sensitivity runs for an optimized field development strategy.
Geological modeling separated the field into two models to study the variation of properties on the east and west side. The east section shows a higher porosity and lower saturations. Those water saturations increase below the main pay zone indicating a potential water source. In addition, special core analysis shows a strong oil-wet nature of the reservoir rock. In the east section, sensitivity runs included infill development and variations in landing depth. It is noted that the production is not sensitive to landing zone because fracture geometry is primarily controlled by vertical stress profile. In the west section, sensitivity runs included refrac, infill drilling, and a greenfield development plan with variations on well spacing and completion design. The observation shows tighter well spacing or cluster spacing accelerates the oil production in early time, while yielding similar long term oil recovery and shows a combination of refrac and infill drilling yields a 21% incremental oil production beyond the base case.
This study provides valuable information about the workflow to develop tight oil plays by describing a detailed case study. The result also sheds light on the optimized field development strategy for analogous fields.
Alcorn, Zachary P. (University of Bergen) | Fredriksen, Sunniva B. (University of Bergen) | Sharma, Mohan (University of Stavanger) | Rognmo, Arthur U. (University of Bergen) | Føyen, Tore L. (University of Bergen and SINTEF Industry) | Fernø, Martin A. (University of Bergen) | Graue, Arne (University of Bergen)
A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) field pilot research program has been started to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic-CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results because of injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a comprehensive integrated multiscale methodology is required for project design to better link laboratory- and field-scale displacement mechanisms. This study presents an integrated upscaling approach for designing a miscible CO2-foam field trial, including pilot-well-selection criteria and laboratory corefloods combined with reservoir-scale simulation to offer recommendations for the injection of alternating slugs of surfactant solution and CO2, or surfactant-alternating-gas (SAG) injection, while assessing CO2-storage potential.
Laboratory investigations include dynamic aging, foam-stability scans, CO2-foam EOR corefloods with associated CO2 storage, and unsteady-state CO2/water endpoint relative permeability measurements. Tertiary CO2-foam EOR corefloods at oil-wet conditions result in a total recovery factor of 80% of original oil in place (OOIP), with an incremental recovery of 30% of OOIP by CO2 foam after waterflooding. Stable CO2 foam, using aqueous surfactants with a gas fraction of 0.70, provided mobility-reduction factors (MRFs) up to 340 compared with pure-CO2 injection at reservoir conditions. Oil recovery, gas-mobility reduction, producing-gas/oil ratio (GOR), and CO2 utilization at field pilot scale were investigated with a validated numerical model. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.
As long as Stokes law or low viscosity Newtonian fluids have been available, common knowledge within the industry has been that whenever these fluids are utilized during the hydraulic fracturing process, very rapid settling of any conventional proppant occurs. Over the years, there have been occasional jobs pumped where the larger sized proppant was the initial proppant pumped, followed by the smaller meshed sand, ceramic or bauxite materials. Little attention was paid to this differing sort of treatment, due to the belief in piston like displacement of proppant regardless of fluid type. Commonly curable resin-coated sand was always pumped in the very last slurry stage of a fracturing treatment, in the common hopes of controlling any potential sand production from the near wellbore area when operations were concluded and flow back operations were initiated to bring the well on line. In reality, with typical over flush volumes, any resincoated sand pumped during a slick water treatment will travel far away from the wellbore.
Recently, the miscible CO2-EOR tertiary process used in the main pay zone (MP) of suitable reservoirs has broadened to include exploitation of the underlying residual oil zone (ROZ) where a significant amount of oil may remain. The objective of this study is to identify the ROZ and to assess the remaining oil in a brownfield ROZ by using core data and conventional well logs with probabilistic and predictive methods.
Core and log data from three wells located in the East Seminole Field in Gaines County, Texas, were used to identify the MP and ROZ in the San Andres Limestone, and to predict oil saturations. The core measurements were used to calculate probabilistic in-situ oil saturations within the MP and the ROZ as a function of depth. Well logs, in combination with core data and calculated saturations, on the other hand, were used to develop two expert systems using artificial neural networks (ANN); one to identify the ROZ and MP, and the other to predict oil saturation. These systems were also supported by a classification and regression tree (CART) analysis to delineate the rules that lead to classifications of zones.
Results showed that expert systems developed and calibrated by combining core and well log data can identify MP and ROZ with a success score of more than 90%. Saturations within these zones can be predicted with a correlation coefficient of around 0.6 for testing and 0.8 for training data. The analyses showed that neutron porosity and density well log readings are the most influential ones to identify zones in this field and to predict oil saturations in the MP and ROZ. To explain the relationships of input data with the results, a rule-based system was also applied, which revealed the underlying petrophysical differences between MP and ROZ.
This new predictive approach using machine learning techniques, could potentially address the challenges that previous studies have come up against in defining the ROZ within the formation and quantifying remaining oil saturations. The method can potentially be applied to additional fields and help reliably identify the ROZ and estimate saturations for future resource evaluations.
This paper presents modeling CO2 enhanced oil recovery (EOR) flood performance through the application of dimensionless scaling for both forecasting and surveillance purposes. While the methodology has been used successfully for West Texas CO2 floods for more than two decades, a recent modification in the process enhances the certainty of forecasted tertiary response based on simulation and analog results. The primary focus of this paper is on how this new approach improves the use of analog or observed production history to develop more reliable forecasts for EOR processes. Business units favor analog methods since they are fast, adaptable and explicit.
Analog tertiary production response is the incremental oil production over an estimated base waterflood oil recovery. The original formulation, published in a different paper (
La Cira Infantas is the oldest oil field in Colombia. It has approximately 100 years of production, and it is located in the Middle Magdalena Valley Basin, producing from a black oil multilayered and heterogeneous sandstone reservoir. Primary production began in 1918 until 1959 when the first water flooding process began. In 2005, Oxy Colombia and Ecopetrol initiated a joint venture of a new redeveloped water flooding process. Since the joint venture, the field has expanded to 400 patterns and 1,000 active producer wells, 95% of which are under a water flooding process. The redesign of the field considers 20-acre to 25-acre on average and 5-spot to 7-spot inverted patterns. Injector wells have a selective string completion, with mandrels and packers that allow having control on the vertical distribution of the volume of water per mandrel group. In order to monitor water flood performance in the field, a reservoir surveillance methodology, based on dimensionless variables, has been implemented.
The methodology was originally applied for a CO2 flood surveillance and was later extended to fit water flooding monitoring purposes. The paper presents the application of the dimensionless methodology, which allows the evaluation of water flood areas independently of their pattern configuration. This allows the comparison between patterns, sector or areas versus a theoretical ideal performance curve and quickly identify underperforming patterns in order to propose remedial actions.
The application of this methodology has opened new opportunities in the field including the identification of well candidates for chemical stimulation jobs and conformance jobs, isolation jobs in producer wells as well as pump upsize opportunities. Additionally, it has improved the technical evaluation of workover jobs. Because of this, in the last four years La Cira Infantas has extended its portfolio activity, executing over 400 workover jobs. More importantly, it has allowed the transfer of more than 20MMBO into PDP reserves, and the production of 3,000BOPD of incremental oil production per year since 2014.
This paper will provide an insight into the water flooding surveillance carried out in La Cira Infantas, which has proven to be very successful in Oxy's business units.
A miscible injectant was used in a single injection well pilot in the Yates field to mobilize remaining oil in the gas cap and accelerate gravity drainage. Nitrogen, CO2 and recycled gas injection, all immiscible with Yates oil due to low original and current reservoir pressure, have been used historically to assist the gas-oil gravity drainage (GOGD) development. The result of immiscible injection has been a lowering of the gas-oil contact, a thinning of the oil column, and leaving a remaining oil saturation in the gas cap of up to 40 percent. A hydrocarbon mixture rich in ethane and propane and miscible with Yates oil was injected in a CO2 injector for six months after which the well was returned to pure CO2 injection.
Data collection during the pilot included repeat saturation logging of a newly drilled observation well, well tests of nearby horizontal producers, frequent gas and oil sampling, and chromatographic analysis. Phase behavior PVT experiments were also conducted which confirmed miscibility of the injectant and improvement over CO2 injection. Numerical simulation of pilot performance was also used as part of the interpretation.
Pilot results to date show a doubling of oil rate at peak over base oil decline, breakthrough in horizontal producers within 3-5 months matching an a priori prediction from numerical simulation, 10 percent reduction in oil saturation in the target interval in the gas cap, and the return of two wells to continuous production after having been shut-in due to high gas-oil ratios. Early interpretation of pilot results showed that most of the incremental oil and back produced enriched hydrocarbons came from one well. During the follow-up CO2 injection phase, one of the horizontal wells completed in the gas cap (unlike other pilot producers), was redrilled deeper into the oil column to improve the pilot areal and vertical sweep.
The pilot design, results, and interpretation will be discussed. Results from the pilot will be used to support evaluation of a field wide development, which could lead to substantial incremental reserves and extension of the field life.
Alcorn, Z. P. (Department of Physics and Technology, University of Bergen) | Fredriksen, S. B. (Department of Physics and Technology, University of Bergen) | Sharma, M. (The National IOR Centre of Norway, University of Stavanger) | Rognmo, A. U. (Department of Physics and Technology, University of Bergen) | Føyen, T. L. (Department of Physics and Technology, University of Bergen) | Fernø, M. A. (Department of Physics and Technology, University of Bergen) | Graue, A. (Department of Physics and Technology, University of Bergen)
A CO2 foam enhanced oil recovery (EOR) field pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results due to injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a more integrated multiscale methodology is required for project design to further understand the connection between laboratory and field scale displacement mechanisms. Foam is frequently generated in a reservoir through the injection of alternating slugs of surfactant solution and gas (SAG). To reduce costs and increase the success of
Laboratory investigations include dynamic aging, foam stability scans, CO2 foam EOR corefloods with associated CO2 storage, and unsteady state CO2/water endpoint relative permeability measurements. Wettability tests of restored reservoir core material yield Amott-Harvey index values of −0.04 and −0.79, indicating weakly oil wet to oil wet conditions. Foam scans demonstrate highest foam quality at gas fraction (fg) of 0.70. CO2 foam EOR corefloods after completed waterfloods, at optimal foam quality, result in a total recovery factor of 80% OOIP with an incremental recovery of 35% OOIP by CO2 foam.
A negligible difference is observed in incremental CO2 foam recoveries and apparent viscosities when using 1 wt% and 0.5wt% surfactant solution. High differential pressures during CO2 foam suggest generation of stable foam with mobility reduction factors by CO2 foam up to 340, over CO2 at reservoir conditions. CO2 storage potential was assessed during displacement to investigate the carbon footprint of CO2 foam injection.
Relative permeability endpoints and foam stability scan parameters are input into a validated field scale numerical simulation model to recommend design parameters for SAG injection. The numerical model investigates foam's impacts on oil recovery, gas mobility reduction, producing gas oil ratio (GOR), and CO2 utilization. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.
Alimahomed, Farhan (Schlumberger) | Haddad, Elia (Schlumberger) | Velez, Edgar (Schlumberger) | Foster, Randy (Triumph Exploration) | Downing, Terrell (Triumph Exploration) | Seth, Cody (Triumph Exploration) | Melzer, Steve (Melzer Consulting) | Downing, Will (Melzer Consulting)
The San Andres is one of the most prolific conventional carbonate plays in the Permian Basin. It primarily occurs in the Central Basin Platform, but some fields are spread throughout the Northwest Shelf. The variation of the log profiles across the platform indicates a staged history and, challenging geological setting, which can have an impact on the lateral variability, landing zones and the completion techniques. Horizontal wells being a relatively new way to exploit this play, there are several challenges associated with making it economic. These challenges were faced in a program involving three horizontal wells on the Central Basin Platform. High tier petrophysical and sonic logs in the pilot, sonic and image logs in the lateral, and real-time microseismic data, were analyzed in the program.
Integrating data from various disciplines such as geology, petrophysics, geomechanics, completion engineering and reservoir engineering plays a significant role in identifying trends and key drivers of production. In the San Andres three-well program, high-tier petrophysical and sonic logging data were collected in the vertical pilot well. A fracture injection test (FIT) was performed to calibrate the rock properties. A 3D geomodel was built around the area of interest using well tops from offset vertical wells, and was refined to a localized structure around individual wellbores using dips from lateral image logs. Fracture simulations were performed to determine the optimum job size to cover the pay zone. Image logs in the lateral were interpreted for fractures and bedding planes, and to understand the changes in rock facies along the length of the lateral. Open hole sonic measurements in the lateral were used to place perforations in similar type of rock based on good reservoir quality and completion quality. Laboratory tests were performed on oil samples to determine the oil properties. Cuttings were analyzed to determine their solubility with acid. Two horizontal wells were monitored using real-time downhole microseismic. Post job analysis was performed to tie all the observations together.
Analysis of the injection test indicated slightly lower than normal reservoir pressure. Pilot-hole logs indicated a variable zone with mobile oil (pay) which was overlain on the top by anhydrite stringers and beds; higher water saturations were observed below the zone. The three horizontal wells in this program were all landed at various depths from the mobile oil interval to understand the impact on production. Step down tests were performed and analyzed on several stages to quantify near-wellbore friction pressures. Microseismic data showed planar features in stages that had fewer fractures identified on the image logs. High treating pressures were observed on alternate stages indicating some degree of stress shadow. Image logs in the laterals showed features such as anhydrite nodules and distinct layering of the rock, which can have a significant impact on the hydraulic fracture growth and also on production. The analysis of the fracture treatment and microseismic data yielded important information, and the program included the adoption of appropriate technologies and formulation of workflows for effective analysis.
The San Andres wells have been cost effective to drill and complete throughout the oil price downturn, but there are still many questions to be answered to make it an extremely successful play. The results and observations from this three-well program provide insights that will assist in planning and designing future projects.