This article presents brief summaries of detailed petrophysical evaluations of several fields that have been described in the SPE and Soc. of Professional Well Log Analysts (SPWLA) technical literature. These case studies cover some of the complications that occur when making net-pay, porosity, and water saturation (Sw) calculations. Prudhoe Bay is the largest oil and gas field in North America with more than 20 billion bbl of original oil in place (OOIP) and an overlying 30 Tscf gas cap. In the course of this determination, an extensive field coring program was conducted, which resulted in more than 25 oil-based mud (OBM) cores being cut in all areas of the field and some conventional water-based mud (WBM) and bland-mud cores in other wells. The background geologic understanding of the major reservoir, the Ivishak or Sadlerochit, and various technical studies have been presented in a number of technical papers.
Miscible injection is a proven, economically viable process that significantly increases oil recovery from many different types of reservoirs. Most miscible flooding projects use CO2 or nitrogen as solvents to increase oil recovery, but other injectants are sometimes used. This page provides an overview of the fundamental concepts of miscible displacement. Also provided are links to additional pages about designing a miscible flood, predicting the benefits of miscible injection, and a summary of field applications. Fieldwide projects have been implemented in fields around the world, with most of these projects being onshore North American fields.
In the early days of the oil industry, saline water or brine frequently was produced from a well along with oil, and as the oil-production rate declined, the water-production rate often would increase. This water typically was disposed of by dumping it into nearby streams or rivers. In the 1920s, the practice began of reinjecting the produced water into porous and permeable subsurface formations, including the reservoir interval from which the oil and water originally had come. By the 1930s, reinjection of produced water had become a common oilfield practice. Reinjection of water was first done systematically in the Bradford oil field of Pennsylvania, U.S.A. There, the initial "circle-flood" approach was replaced by a "line flood," in which two rows of producing wells were staggered on both sides of an equally spaced row of water-injection wells. In the 1920s, besides the line flood, a "five-spot" well layout was used (so named because its pattern is like that of the five spots on ...
Wilson, Tawnya (Pioneer Natural Resources) | Handke, Michael (Pioneer Natural Resources) | Loughry, Donny (Pioneer Natural Resources) | Waite, Lowell (Pioneer Natural Resources) | Lowe, Brandon (Pioneer Natural Resources)
Over the last decade, the growth of unconventional resource development in the Midland Basin has significantly increased the disposal of produced water volumes. Disposal into the historic Grayburg-San Andres (GYBG-SNDR) reservoir has resulted in a dynamically changing pore pressure environment relative to deeper producing formations which is important to consider when planning drilling operations throughout the basin. A deep understanding of the GYBG-SNDR geology is imperative for reservoir management to ensure that produced water disposal does not hinder oil and gas production operations. This study describes the geologic controls on porosity and permeability distributions in GYBG-SNDR across the Midland Basin by utilizing core, modern well log suites, 3D seismic data, and saltwater disposal (SWD) well data.
In 2017, Pioneer acquired more than 1,000 feet of core in three wells over the GYBG-SNDR injection interval which were used to describe the depositional and diagenetic facies and calibrate a petrophysical model for a basin-wide well log dataset. The resultant log curves were used to construct maps describing the abundance and regional distribution of each lithology, which validated and further refined the depositional model. Observations resulting from the integration of the lithology maps, 3D seismic data, well log correlations and core were used to divide the basin into three distinct areas based upon the dominant lithologies and stratigraphic architecture. The three areas are separated by two major shelf margins representing a significant sea level drop at that time. These basin-wide trends provide a regional geologic framework in which to analyze SWD well performance.
Numerous geologic maps were created and tested against quality-checked and normalized SWD well performance data. Despite some scatter in the data (due to the differences in how the wells are operated, completed, and maintained) a positive linear correlation was found between SWD well performance and permeable dolomite footage. Additionally, anhydrite is most abundant in the northeastern part of the basin and is qualitatively associated with a decrease in permeable dolomite thickness, and therefore performance. Mapped matrix permeability is enhanced by fracture permeability related to syndepositional margin collapse and reactivation of older faults during the Laramide Orogeny. These features are documented throughout the Midland Basin using proprietary 3D seismic datasets and have been shown to be conduits for fluid flow resulting in dissolution and further dolomitization in some areas.
San Andres and Clearfork are two carbonate reservoir intervals that are present over a considerable area of the Permian Basin in west Texas. These reservoirs (e.g., Wasson, Slaughter, Seminole) contain several billion bbl of approximately 30 API oil. They are very-layered, heterogeneous carbonates and dolomites that have large variation in permeability from layer to layer. Interestingly, because of the complex hydrocarbon-accumulation history of this basin, much of this area has an underlying interval that contains residual oil saturation. Most of these reservoirs were discovered in the late 1930s and the 1940s.
The primary purpose of using traditional friction reducers in stimulation treatments is to overcome the tubular drag while pumping at high flow rates. Hydraulic fracturing is the main technology used to produce hydrocarbon from extremely low permeability rock. Even though slickwater (water fracturing with few chemical additives) used to be one of the most common fracturing fluids, several concerns are still associated with its use, including usage of freshwater, high-cost operation, and environmental issues. Therefore, current practice in hydraulic fracturing is to use alternative fluid systems that are cost effective and have less environmental impact, such as fluids which utilize high viscosity friction reducers (HVFRs), which typically are high molecular weight polyacrylamides. This paper carefully reviews and summarizes over 40 published papers, including experimental work, field case studies, and simulation work. This work summarizes the most recent improvements of using HVFR’s, including capability of carrying proppant, reducing water and chemical requirements, its compatibility with produced water, and environmental benefits in hydraulic fracturing treatments. A further goal is to gain insight into the effective design of HVFR based fluid systems.
The findings of this study are analyzed from over 26 field case studies of many unconventional reservoirs. In comparing to the traditional hydraulic fracture fluids system, the paper summaries many potential advantages offered by HVFR fluids, including: superior proppant transport capability, almost 100% retained conductivity, cost reduction, minimizing chemicals usage by 50%, less operating equipment on location, reducing water consumption by 30%, and fewer environmental concerns. The study also reported that the common HVFR concentration used was 4gpt. HVFRs were used in the field at temperature ranges from 120°F to 340°F. Finally, this work addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.
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.