The electromagnetic heating of oil wells and reservoirs refers to thermal processes for the improved production of oil from underground reservoirs. The source of the heat, generated either in the wells or in the volume of the reservoir, is the electrical energy supplied from the surface. This energy is then transmitted to the reservoir either by cables or through metal structures that reach the reservoir. The main effect, because of the electrical heating systems used in practice in enhanced oil recovery, has been the reduction of the viscosity of heavy and extra heavy crudes and bitumens, with the corresponding increase in production. Focus is centered on systems (and the models that describe their effects) that have been used for the electromagnetic heating in the production of extra heavy petroleum and bitumen.
Principles for Polycrystalline Diamond Compact (PDC) bit design are discussed here. Each of these factors must be considered on an application-to-application basis to ensure achievement of rate of penetration (ROP) goals during cooling, cleaning the bit, and removing cuttings efficiently. During design, all factors are considered simultaneously. Cutting structures must provide adequate bottomhole coverage to address formation hardness, abrasiveness, and potential vibrations and to satisfy productive needs. Early (1970s) PDC bits incorporated elementary designs without waterways or carefully engineered provisions for cleaning and cooling.
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.
Actually, the definition of a tight gas reservoir is a function of many factors, each relating to Darcy's law. The main problem with tight gas reservoirs is that they do not produce at economic flow rates unless they are stimulated--normally by a large hydraulic fracture treatment. Eq. 7.1 illustrates the main factors controlling flow rate.
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.
As the quest for new petroleum supplies has increased in the past few years, operators have been forced to drill deeper to find new reserves. Much of the higher cost of drilling deeper, especially onshore, is typically associated with decreased rate of penetration (ROP) caused by both harder rock and higher mud weights required to counter the overpressured reservoirs often associated with deeper drilling. The following discussion centers on technologies intended to enhance the deep drilling capability. Industrial hammers for hard rock drilling have been around for some time, but most have been air operated and used in the mining industry. Historically, hammers have been thought to have limited capability in oil and gas drilling operations, with their use limited to air drilling.
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 ...
The Cretaceous Eagle Ford of South Texas is a major unconventional play. Age equivalent rocks are present in the adjacent Burgos Basin, Mexico along with other unconventional targets in the Jurassic. The objective of this study was to map areas of unconventional potential from basinwide maturity predictions provided by 3D modeling. This study has identified oil, wet gas and dry gas areas of interest for the Cretaceous and Jurassic targets. These areas of interest can then be used to focus followup studies by companies or institutions evaluating joint ventures and/or lease sale blocks in the basin.
The 3D model for the Burgos Basin was made using publicly available information. Regional structure maps were made by integrating published structure maps and cross sections. Structure maps, temperature gradients from well logs and a tertiary erosion map were the key inputs used to model maturity. The Cretaceous Agua Nueva and the Jurassic La Casita/Pimienta Formations were the primary zones of interest. Rock maturity data was available for one Cretaceous and one Jurassic well. The model was also verified by comparing to Cretaceous and Jurassic unconventional well results.
Structural strike of the Eagle Ford in south Texas is southwest to northeast. Near the border structural strike abruptly changes to nearly north - south. In the Burgos Basin, the Mesozoic section dips eastward toward the Gulf of Mexico due to over 30,000 feet of Tertiary sand and shale deposition. Faulting in the Tertiary section generally soles out above the Mesozoic, so the Mesozoic is mostly tectonically undisturbed which is favorable for unconventional targets.
The prospective area for the Cretaceous and Jurassic is essentially coincident and is over 40 miles wide and 300 miles long. The prospective area was defined according to depth and modeled vitrinite reflectance equivalence (VRE). Measured depths of 5,000 to 15,000 feet and VRE greater than 0.8 were used. The rationale was that shallower than 5,000 feet would have low pressure and temperature and greater than 15,000 feet would have too high a well cost for horizontal wells. The oil prospective area is from 0.8 to 1.1 VRE, wet gas from 1.1 to 1.7 VRE and dry gas over 1.7 VRE. Oil spacing was assumed to be 100 acres and gas spacing 200 acres. Total recoverable resources are estimated at approximately 27 BBOE of which 15% are liquids (oil and condensate) and 85% are gas.
The size of the individual seismic surveys has increased over the last decade, along with the generation of megamerge and even larger, what some operators call “gigamerge” surveys. The number of useful attribute volumes has also increased, such that interpreters may need to integrate terabytes of data. During the past several years, various machine learning methods including unsupervised, supervised and deep learning have been developed to better cope with such large amounts of information. In this study we apply several unsupervised machine learning methods to a seismic data volume from the Barents Sea, on which we had previously interpreted shallow high-amplitude anomalies using traditional interactive interpretation workflows. Specifically, we apply k-means, principal component analysis, self-organizing mapping and generative topographic mapping to a suite of attributes and compare them to previously generated P-impedance, porosity and Vclay displays, and find that self-organized mapping and the generative topographic mapping provide additional information of interpretation interest.
In the late 1980s, seismic facies analysis was carried out on 2D seismic data by visually examining the seismic waveforms that can be characterized by their amplitude, frequency and phase expression. Such information would be posted on maps and contoured to generate facies maps. As seismic data volumes increased in size with the adoption of 3D seismic data in the early 1990s, interpreters found that 3D seismic attributes highlighted patterns that facilitated the human recognition of geologic features on time and horizon slices, thereby both accelerating and further quantifying the interpretation. More recently, computer-assisted seismic facies classification techniques have evolved. Such methods or workflows examine seismic data or their derived geometric, spectral, or geomechanical attributes and assign each voxel to one of a finite number of classes, each of which is assumed to represent seismic facies. Such seismic facies may or may not represent geologic facies or petrophysical rock types. In this workflow, well log data, completion data, or production data are then used to determine if a given seismic facies is unique and should be lumped (or “clustered”) with other similar facies determined from attributes with similar attribute expression.
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.