Relative permeability and capillary pressure defines relative permeabilities as dimensionless functions of saturation with values generally ranging between 0 and 1. Relative permeability is important for estimating the flow of reservoir fluids. The semilog scale of Figure 1 is convenient for reading the relative permeabilities less than 0.05. Although the curves are labeled "gas" and "oil" in these figures, the phase identity of a curve can be deduced without the labels. For example, the relative permeability that increases in the direction of increasing oil saturation must be the oil relative permeability.
Water is the wetting phase. Figure 1.5 – Primary drainage, imbibition, and secondary drainage for an oil/water system in which the oil and water wet the solid surface equally. Figure 1.6 – Primary drainage and imbibition for unconsolidated dolomite powder (the lines merely connect the data). These authors wrote capillary pressure as the negative of Eq. 4 because oil was the wetting phase for most of the tests. The legend gives contact angles measured through the water phase (in degrees). Leverett and coworkers, based on the evaluation of gas/water capillary pressure data for drainage and imbibition in unconsolidated sands, proposed the following definition: ....................(15.6) The function j(Sw), defined in Eq. 15.6, is known to many as the "Leverett j-function." The j-function is obtained from experimental data by plotting against Sw. The combination is often considered an estimate of the mean hydraulic radius of pore throats.
Wang, Bingjie (CNOOC LTD.-TianJin Bohai Oilfield) | Xu, Changgui (CNOOC LTD.-TianJin Bohai Oilfield) | Wu, Kui (CNOOC LTD.-TianJin Bohai Oilfield) | Zhang, Rucai (CNOOC LTD.-TianJin Bohai Oilfield) | Deng, Jun (CNOOC LTD.-TianJin Bohai Oilfield) | Guo, Naichuan (CNOOC LTD.-TianJin Bohai Oilfield)
A new oil property identification parameter (Pw) is derived which represents the total hydrocarbon generation and pyrolysis hydrocarbon. Using continuous measurement data (Pw) and a series of samplebased attributes from 3D seismic, a strong linear trend is observed. This trend linear is used to calculate heavy oil property data in 3D volume. At the same time, we have got the relationship between reservoir physical and oil properties. Based on this, the core data and geochemical data are used to study the charging of crude oil.
Some of the most prolific oil fields in the world have been produced or are operating under complete water drives through all or substantial parts of their producing lives. The most celebrated example is, of course, the East Texas field. Others are the fault-line fields in Texas' --Powell, Wortham, Currie, Richland, and Mexia--the Frio reservoir at Thompson in Texas, many of the fields in Kansas, and some of the Arbuckle Limestone fields in Arkansas. Many of the more recently developed fields in Mississippi, as Pickens, Tinsley, Eucutta, and Heidelberg, produce such highly tmdersaturated crudes that they can develop no gas-drive components until the pressures have fallen to small fractions (of the order of M to M) of their initial reservoir pressures.
Two different sources of H2S have been identified in the ultra-sour gases in the Arab Formation in Abu Dhabi, based on sulfur isotope measurements of both anhydrites and H2S. In the Upper Arab reservoirs, H2S appears to be generated
Drilling and production onshore and offshore Mexico have substantiated U. Jurassic source rocks as effective source rocks for conventional and now unconventional petroleum resources. The U. Jurassic section in the Tampico-Misantla basin has excellent source rock characteristics for oil generation based on good original TOC values and hydrogen indices indicative of oil prone marine organic matter. From a mineralogical viewpoint, these shales (or mudstones) are generally very high in carbonate content that is conducive to unconventional production potential.
Data from various source rock oil reservoir systems show that the overall petroleum composition is significantly different from juxtaposed, organic-lean, non-source rock intervals as well as produced petroleum at the wellhead or separator. Thus, it is necessary to understand the in situ petroleum composition of the source rock if that is the completion objective. Petroleum composition affects physicochemical properties such as API gravity, viscosity, and gas-to-oil ratio (GOR). For example, the amount of the polar compounds (NSOs) is inversely proportional to API gravity and saturated hydrocarbon content. It then is important to discriminate the oil type and related phase as black oil, volatile oil, condensate-NGL, and dry gas by correlative and direct indications of such composition.
At higher thermal maturities, oil quality increases rapidly as the non-hydrocarbon constituents of petroleum are cracked to hydrocarbons and refractory carbonaceous residues. There is an exponential increase in GOR in the volatile oil to the earliest gas window, albeit appearing linear in the black oil window. The key is to relate the physicochemical properties of petroleum to correlative tools, i.e., thermal maturity measurements, and direct indicators of sub-surface oil properties and phase.
A combination of visual and chemical measurements, when available, are used to risk thermal maturity assessments including vitrinite and solid hydrocarbon reflectance, Tmax, hydrogen index, gas composition, gas carbon isotopes, and aromatic hydrocarbons. These values are integrated into an interpretive thermal maturity and related to surface and subsurface API gravity and GOR values. Reasonable thermal maturity interpretation allows restoration of the petroleum generation potential for any given sample analyzed by determining the level of kerogen conversion and also taking into consideration secondary cracking. This permits computation of restored TOC, hydrogen indices, and pyrolysis (S2) yields. From these results, the total generation potential can be estimated along with expelled and retained petroleum contents. Comparing these reverse model results with forward model results using restored total oil (S1total) allow a check and a comparative estimate of expulsion as otherwise estimated. These predictions are further checked by slope factor analysis allowing PVT-like restoration of oil and gas yields.
Integrated evaluation of unconventional shale is a basic need for drilling and evaluation, as well as for completion and production. A large number of isotropic and anisotropic rock properties were measured and thoroughly verified. One of the interesting observations during the study was the values obtained for Poisson's ratio for vertical transverse isotropic (VTI)-like material such as Haynesville shale. A typical nonsymmetrical Poisson's ratio obtained from reliable sources and measured in the current work was presented, compared and analyzed. The five elastic constants that describe constitutive behavior were critically reviewed. Finally, the Poisson's ratio was found to be nonsymmetrical, obeying the necessary equality with Young's modulus, which is rarely observed in the geomechanics literature. The nonsymmetrical Poisson's ratio has a special bearing in analyzing anisotropic materials behavior and is used for in-situ stress estimations and hydraulic fracturing.
Integrated evaluation of unconventional shale is a basic need for drilling and evaluation, as well as for completion and production. These evaluations are necessary to assess the resources available, the type of hydrocarbon reserves, planning for the best potential well, the landing need from vertical to lateral, the direction of the well, the type of fluid to be used for drilling, how the well will respond to drilling, and how the well will respond to successive stages for hydraulic fracturing. Market research indicates that as much as $7B is spent on unconventional wells in the USA that do not reach or stay within the potentially highest-producing intervals of the reservoirs. In addition, approximately 70% of operators say they do not know enough about the unconventional subsurface. Only 30% of the time do operators claim to know enough to drill and complete wells with confidence. Consequently, it is necessary to understand the true behavior of shale, especially with its unique characteristics that are regularly used as inputs in models or computer code modeling for drilling, evaluation, completion or production.
A large amount of work was done in characterizing shale using an integrated approach that includes mineralogical, physical, mechanical and petrophysical properties, including downhole and laboratory measurements (LeCompte et al., 2009 ; Sone, 2012; Prasad et al., 2015 ). However, often mechanical property details are ignored and not investigated because of complications originating from the fissile nature of shale. Sample preparation is difficult, and sometimes impossible. Further, the measured geomechanical properties show wide scatter, reflecting inherent depth variability and rock heterogeneity. Wireline logs provide near-continuous data but rarely yield direct measurements of rock mechanical properties, so correlations are needed to obtain static rock mechanical properties. It is very important to have quality assurance and quality control (QA/QC) on laboratory-measured properties (Prasad et al., 2015 ) for calibrating log-based static rock mechanical properties because pre-existing correlations might not be adequate for a particular field. The present work shows a case study for characterizing Haynesville shale as an integrated approach at both ambient and 120°C. A special emphasis was given measuring and discussing non-symmetric Poisson's ratio from dynamic measurements.
High-pressure/high-temperature (HP/HT) wells demand the highest-performance equipment and services for the safe and successful completion of these high-risk and high-cost projects. The demands associated with logging, shoe-track isolation, equipment longevity and service life, completion and intervention options, and regulatory compliance push the limits of materials and services. The successful completion of HP/HT wells requires advanced materials evaluations, collaboration among many disciplines, and sufficient time for product development and assessment to meet current industry and regulatory standards. The tools used in HP/HT completions are usually developed to meet the demands of a well or a family of wells. These tools include, but are not limited to, wellbore-isolation plugs, production packers, liner hangers, perforating guns, casing-collar-locator (CCL) tools, formation-evaluation tools, seal assemblies, and subsurface safety valves. The methods used for HP/HT tool development are evolving, and the development cycles are lengthening, particularly for ultra-HP/HT applications in which materials screening and stability assessments are required. The development of tools for several recent Gulf of Mexico ultra-HP/HT wells required a multiyear schedule for development to industry and regulatory requirements. Because of their extreme depths, ultra-HP/HT wells are typically constructed architecture emphasizing small production casings across production intervals. This complicates cementing procedures, and severely limits product options. From an intervention standpoint, work-string options also become limited. Achieving mechanical success in these applications requires the operator to manage not only traditional resources such as time, people, and cash, but also the development of new high-performance technologies in an evolving regulatory environment. What can the industry anticipate for future HP/HT wells in terms of architecture, product development, and regulatory challenges? This paper reviews the industry’s history in these areas, identifies current development paradigms, and discusses the future challenges in well planning and product development.
The main structural features affecting the Mesozoic sequences of the Gulf rim are a series of interior salt basins extending from south Texas to Alabama. These basins formed during the rifting stage of the formation of the Gulf of Mexico. The early Oxfordian Smackover Formation, characterized by organic-rich, carbonate source rock intervals, represents the initial phase of the Late Jurassic marine transgression in the Gulf of Mexico Basin, where a density-stratified shallow sea was developed. It is predominantly composed of carbonates and calcareous shales and can easily be correlated by its lithology for considerable distances along its depositional strike. Over most of the Gulf coast, it can be subdivided into two distinct units. The Lower Smackover Formation (Brown Dense) is composed of dark-colored, organic-rich carbonate mudstone and dense argillaceous limestone deposited in a low-energy setting, while the Upper Smackover Formation is typically composed of coarser, grain-supported, porous carbonates formed in a high-energy shallow-water environment. Oil and gas resources have been produced from the more porous upper unit on which most geologic works have mainly focused. The Brown Dense has been, however, less studied, although it could become a viable resource play with the utilization of modern drilling techniques.
Recently collected 450-ft (ca. 137 m) thick core and full-suite well logs have been studied to delineate geologic features, the results of which would be significant impact on exploration programs. The detailed geologic studies have revealed that 1) the Brown Dense interval comprises the multi-stacked cyclic succession, having the coarsening-upward trend, in which the basal part is dominated with organic-rich deposits, grading upward into algal laminite-like deposits, 2) each coarsening-upward succession (interpreted as parasequence), sharply demarcated by flooding surface, would be deposited during a regression period, 3) the porosity-permeability trend is characterized by organic-rich deposits that have relatively high effective porosity (average > 3%) and permeability (up to 5 µD), respectively 4) the presence of framboidal pyrites is mostly associated with organic-rich layers, where relatively high porosity is evident, 5) porosity is mainly comprised of the shelter type with some amounts of interparticle and intraparticle pores, and 6) cementation might be severe throughout the entire interval, but it would be limited within the organic layers.
Six years ago, the Upper Jurassic Haynesville Shale play was largely unknown as an unconventional shale play. US government and oil company resource assessments for such unconventional plays vary significantly. Here we attempt to estimate resource potential using a full mass balance approach based on data from more than 1600 recently drilled wells, integrated into a 3D petroleum systems model.
Numerous iterations were conducted to simulate heat flow in the study area. The simulated heat flow calibrated to vitrinite reflectance data from 26 wells suggests that a slight increase in heat flow may have occurred with every uplift event over the Sabine Uplift area.
Laboratory analysis of a number of Haynesville Shale samples taken from six wells reported an original total organic carbon (TOC) content, which is on average 3% for all samples. Additional Rock-Eval analysis revealed that all of the samples taken from the wells are overmature. Adsorption isotherms were determined on one representative sample and implemented in the modelling approach to calculate adsorbed gas volumes.
After simulation, the accumulation calculations in the Haynesville Shale revealed a total amount of 2056tcf of adsorbed gas (79.15% Methane) and 1511tcf of free gas (87.12% Methane). These numbers seem to be very high, but considering a recovery factor of 5 or 10% the combined producibility of gas based on our model will be equal to 178 or 357tcf respectively. Most of the primary production of gas occurred during the Aptian-Albian, and secondary cracking produced most of the free gas during the Early-Eocene.
The model also shows wide variability in pore pressure and the generation of abnormal pressures. This variation in pore pressure occurs in the Haynesville Shale and results from a combined effect derived from the overlying Cotton Valley/Bossier Formation and the underlying Smackover Formation. As a final observation, the critical moment of the Haynesville Shale petroleum systems has been dated to be at the Turonian and Early-Eocene. At this point all petroleum system elements and process have been satisfied for the conventional and the nonconventional play respectively.