Showing papers on "Petroleum reservoir published in 2012"

Shale Resource Systems for Oil and Gas: Part 1—Shale-gas Resource Systems

Abstract: Shale resource systems have had a dramatic impact on the supply of oil and especially gas in North America, in fact, making the United States energy independent in natural gas reserves. These shale resource systems are typically organic-rich mudstones that serve as both source and reservoir rock or source petroleum found in juxtaposed organic-lean facies. Success in producing gas and oil from these typically ultra-low-permeability (nanodarcys) and low-porosity (15%) reservoirs has resulted in a worldwide exploration effort to locate and produce these resource systems. Successful development of shale-gas resource systems can potentially provide a long-term energy supply in the United States with the cleanest and lowest carbon dioxide-emitting carbon-based energy source.Shale-gas resource systems vary considerably system to system, yet do share some commonalities with the best systems, which are, to date, marine shales with good to excellent total organic carbon (TOC) values, gas window thermal maturity, mixed organic-rich and organic-lean lithofacies, and brittle rock fabric. A general classification scheme for these systems includes gas type, organic richness, thermal maturity, and juxtaposition of organic-lean, nonclay lithofacies. Such a classification scheme is very basic, having four continuous shale-gas resource types: (1) biogenic systems, (2) organic-rich mudstone systems at low thermal maturity, (3) organic-rich mudstone systems at a high thermal maturity, and (4) hybrid systems that contain juxtaposed source and nonsource intervals.Three types of porosity generally exist in these systems: matrix porosity, organic porosity derived from decomposition of organic matter, and fracture porosity. However, fracture porosity has not proven to be an important storage mechanism in thermogenic shale-gas resource systems.To predict accurately the actual resource potential, the determination of original hydrogen and organic carbon contents is necessary. This has been a cumbersome task that is simplified by the use of a graphic routine and frequency distribution (P50) hydrogen index in the absence of immature source rocks or data sets.

Types,characteristics,genesis and prospects of conventional and unconventional hydrocarbon accumulations:taking tight oil and tight gas in China as an instance

Abstract: It is an inevitable trend for oil and gas industry to transform exploration development domain from conventional hydrocarbon accumulations to unconventional hydrocarbon ones,which are obviously different in types,geological features and genesis.Conventional petroleum focuses on accumulation mechanism,and the key answer is whether the trap contains petroleum,otherwise,unconventional petroleum focuses on the reservoir space,and the key answer is how much the reservoirs capture petroleum.Unconventional hydrocarbon resources are mainly characterized by continuous distribution and no natural oil and gas production from per well.Currently,unconventional problems occur in the exploration and development of conventional hydrocarbon resources,thus it is necessary to transform unconventional hydrocarbon resources into new "conventional" hydrocarbon resources.With technology development,unconventional hydrocarbons can be transformed into conventional ones.Generally,conventional hydrocarbon deposits consist of structural and litho-stratigraphic hydrocarbon reservoirs,where oil and gas are distributed in an isolated structure or a larger structure group with clear trap boundaries and pore-throat systems in millimeter-micrometer scale.Oil and gas in this case accumulate by buoyancy to form hydrocarbon pools.However,unconventional hydrocarbon accumulations,including tight sandstone oil and gas,tight carbonate oil and gas,shale oil and gas,coal-bed methane,oil shale,oil sand,hydrate,etc.,are distributed continuously or quasi-continuously in basin's slopes or centers.Commonly,they are characterized by source-reservoir paragenesis and have no distinct trap boundaries.Pore-throat systems in nanometer scale are well-developed in unconventional reservoir rocks,and related hydrocarbons are mainly detained in situ or migrate for a short distance into reservoirs that are close to source rocks because buoyancy is limited.The present paper systematically analyzed geological characteristics and exploration potential of tight hydrocarbons in some typical basins of China,where pores in nanometer scale with partial micrometer-millimeter pores dominate the reservoir space of unconventional hydrocarbons,the diameter of reservoir pores is 5~200 nm in gas shale,40~500 nm in tight oil limestone,50~900 nm in tight oil sandstone and 40~700 nm in tight gas sand.In terms of the rapid development of globe petroleum industry and nano-technology,a concept of nano-hydrocarbons is proposed in this paper that indicates that "nano-hydrocarbon" is the development direction of oil and gas industry in the future,urgently requiring developing vicarious technologies,such as nano-hydrocarbon perspective viewing mirror,nano-hydrocarbon displacement agent and nano-hydrocarbon exploitation robots.Petroleum intellectualization times will come in following.

Shale Reservoirs: Giant Resources for the 21st Century

Abstract: In the early 1970s, most exploration geologists in the United States considered subeconomic or marginally economic petroleum resources such as coalbed methane, shale gas, and tight-gas sands as unconventional resources (Law and Curtis, 2002). Tax incentives and federally funded research beginning in the late 1970s helped make these resources economically viable in the last two decades of the 20th century. Economics aside, two important geologic attributes characterize most unconventional petroleum resources (Law and Curtis, 2002). Conventional petroleum systems are buoyancy-driven accumulations found in structural or stratigraphic traps, whereas most unconventional systems exist independent of a water column and are generally not found in structural or stratigraphic traps. Shale reservoirs are not new. The first commercial hydrocarbon production in the United States was from a well drilled in 1821 in a shale gas reservoir. By 2000, more than 28,000 wells had been drilled in shale gas reservoirs. Rising gas prices and technological advancements in horizontal drilling and hydraulic fracturing associated with the development of the Barnett Shale led to a boom in shale gas development in the early years of the 21st century. Now the exploitation of shale reservoirs is turning to natural gas liquids, condensate, and oil. Far from being isotropic and homogeneous, as once naively envisioned, shale reservoirs are complexly layered accumulations of fine-grained sediment. Geologic variation on scales ranging from that of stratal architecture to that of lamination within individual beds must be understood in order to locate and exploid areas of higher production within shale reservoirs. Shale reservoirs remain largely geologic plays - notmerely lease plays or strictly engineering plays made possible by improvements in drilling and completion technology.

Zeolite diagenesis and its control on petroleum reservoir quality of Permian in northwestern margin of Junggar Basin, China

Abstract: Recently, silicate diagenesis has been the focus of many studies because of its impact on porosity and permeability in sedimentary rocks. In the process of diagenetic evolution, the crystallization, cementation, and corrosion of zeolite (as a diagenetic mineral) have different effects on properties of Permian reservoirs in the study area. In the Permian sediments in the northwestern margin of the Junggar Basin, Zeolite minerals have formed during diagenesis in an open hydrologic system, related to the hydration of abundant volcanic glass. Chemical property of groundwater, pH of pore water, cation property and ratios have directly influenced the transformation among various zeolites and the dissolution of zeolite mineral. The main species of zeolite include analcime, heulandite, and laumontite. Transformations of these minerals during diagenesis are: volcanic glass→clinoptilolite→analcime→heulandite→laumontite. Corrosion of analcime obviously improved reservoir quality. Extensive heulandite cementation developed and intensively reduced reservoir pore spaces. Early zeolite cementation protected pore structure against compaction and provided substance for late dissolution. The dissolution of analcime was closely related with the organic acid recharged by hydrocarbon source rocks and the NaHCO3 type formation water in the Permian, and was sensitive to permeability of rocks. Within the CaCl2 type formation water, heulandite and laumontite were hardly dissolved. In the study area, the belt with dissolved analcime is the area for the development of secondary pores and favorable reservoirs.

Hydrodynamic stagnation zones: A new play concept for the Llanos Basin, Colombia

Abstract: Hydraulic heads from a calibrated, three-dimensional, constant-density, ground-water-flow model were used to compute Hubbert oil potentials and infer secondary petroleum migration directions within the Llanos Basin, Colombia. The oil potentials for the C7 reservoir show evidence of the development of two hydrodynamic stagnation zones. Hydrodynamic effects on secondary oil migration are greatest in the eastern Llanos Basin, where structural slopes are lowest and local hydraulic-head gradients drive ground-water flow westward down structural dip. The Rubiales field, a large oil reservoir within the eastern Llanos Basin with no structural closure, is located at the edge of one of these stagnation zones. This oil field hosts heavy oils (12 API) consistent with water washing and biodegradation. The best agreement between model results and field conditions occurred in an oil density of 12 API, suggesting that the Rubiales field position is in dynamic equilibrium with modern hydraulic and oil density conditions. Cross sectional ground-water-flow models indicate that the most likely explanation of observed underpressures are caused by hydrodynamic effects associated with a topography-driven flow system. Late Miocene to present-day ground-water flow likely was an important factor in flushing marine connate porewaters from Tertiary reservoirs. Ground-water recharge along the western margin of the basin could help explain the observed low-temperature gradients (20C/km). However, upward flow rates were not high enough to account for elevated temperature gradients of 50C/km to the east.

Outcrop-behind Outcrop (Quarry): Multiscale Characterization of the Woodford Gas Shale, Oklahoma

Abstract: An outcrop-behind outcrop study was conducted in and adjacent to a 300 100 16 m (980 330 50 ft) quarry of the gas-producing Woodford Shale to structurally/stratigraphically characterize it from the pore to subregional scales using a variety of techniques. Strata around quarry walls were described and correlated to a 64 m (210 ft) long continuous core drilled 150 m (500 ft) back from the quarry wall and almost to the Woodford-Hunton unconformity. Borehole logs obtained include neutron and density porosity (NPHI and DPHI) logs, and logs from Elemental Capture Spectroscopy (ECS™), Combinable Magnetic Resonance (CMR-Plus™), Fullbore Formation MicroImager (FMI™), and sonic scanner (Modular Sonic Imaging Platform, or MSIP™)—all manufactured by Schlumberger. The strata around the quarry are horizontally bedded. Borehole logs were used to identify a basic threefold subdivision into an upper relatively porous quartzose interval; a middle, more clay-rich, and less porous interval; and a lower interval of intermediate quartz-clay content. These intervals correspond to the informally named upper, middle, and lower Woodford. Detailed core and quarry wall description revealed several types of finely laminated lithofacies, with varying amounts of total organic carbon (TOC). The FMI log revealed a much greater degree of variability in laminations than can be readily seen with the naked eye. Organic geochemistry and biomarkers are closely tied to these lithofacies and record cyclic variations in oxic-anoxic depositional environments, which correspond to relative sea level fall-rise cycles. At the scanning electron microscopy scale, microfractures and microchannels are common and provide tortuous pathways for gas (and oil) migration through the shales. Based on FMI and core analysis, fracture density is much greater in the upper quartzose lithofacies than in the lower, more clay-rich lithofacies. A laser imaging detection and ranging (LIDAR) survey around the quarry walls documented two near-vertical fracture trends in the quartzose lithofacies: one striking N85E with spacings of 1.2 m (4 ft) and the other striking N45E related to the present stress field. The FMI analysis only imaged the latter fracture set. Both log-derived and laboratory-tested geomechanical property measurements documented a significant relationship between shale fabric (laminations and preferred clay-particle orientation) and rock strength, and a secondary relationship to mineral composition. Porosity and microfractures or microchannels also appear to influence rock strength. This integrated study has provided insight into the causal relations among Woodford properties at a variety of scales. In particular, a stratigraphic (vertical) segregation of lithofacies can be related to cyclic variations in depositional environments. The resulting stratified zones exhibit variations in their hydrocarbon source and reservoir (fracturable) potential. Such information and predictive capability can be valuable for improved targeted horizontal drilling into enriched source rock and/or readily fracturable reservoir rock in the Woodford and perhaps other gas shales.

Characterization of nanometer-scale porosity in reservoir carbonate rock by focused ion beam-scanning electron microscopy.

Abstract: Sedimentary carbonate rocks are one of the principal porous structures in natural reservoirs of hydrocarbons such as crude oil and natural gas. Efficient hydrocarbon recovery requires an understanding of the carbonate pore structure, but the nature of sedimentary carbonate rock formation and the toughness of the material make proper analysis difficult. In this study, a novel preparation method was used on a dolomitic carbonate sample, and selected regions were then serially sectioned and imaged by focused ion beam-scanning electron microscopy. The resulting series of images were used to construct detailed three-dimensional representations of the microscopic pore spaces and analyze them quantitatively. We show for the first time the presence of nanometer-scale pores (50-300 nm) inside the solid dolomite matrix. We also show the degree of connectivity of these pores with micron-scale pores (2-5 μm) that were observed to further link with bulk pores outside the matrix.

Numerical simulations of the Macondo well blowout reveal strong control of oil flow by reservoir permeability and exsolution of gas

Abstract: In response to the urgent need for estimates of the oil and gas flow rate from the Macondo well MC252-1 blowout, we assembled a small team and carried out oil and gas flow simulations using the TOUGH2 codes over two weeks in mid-2010 The conceptual model included the oil reservoir and the well with a top boundary condition located at the bottom of the blowout preventer We developed a fluid properties module (Eoil) applicable to a simple two-phase and two-component oil-gas system The flow of oil and gas was simulated using T2Well, a coupled reservoir-wellbore flow model, along with iTOUGH2 for sensitivity analysis and uncertainty quantification The most likely oil flow rate estimated from simulations based on the data available in early June 2010 was about 100,000 bbl/d (barrels per day) with a corresponding gas flow rate of 300 MMscf/d (million standard cubic feet per day) assuming the well was open to the reservoir over 30 m of thickness A Monte Carlo analysis of reservoir and fluid properties provided an uncertainty distribution with a long tail extending down to 60,000 bbl/d of oil (170 MMscf/d of gas) The flow rate was most strongly sensitive to reservoir permeability Conceptual model uncertainty was also significant, particularly with regard to the length of the well that was open to the reservoir For fluid-entry interval length of 15 m, the oil flow rate was about 56,000 bbl/d Sensitivity analyses showed that flow rate was not very sensitive to pressure-drop across the blowout preventer due to the interplay between gas exsolution and oil flow rate

Salt tectonics, sediments and prospectivity: an introduction

Abstract: Salt is a crystalline aggregate of the mineral halite, which forms in restricted environments where the hydrodynamic balance is dominated by evaporation. The term is used non-descriptively to incorporate all evaporitic deposits that are mobile in the subsurface. It is the mobility of salt that makes it such an interesting and complex material to study. As a rock, salt is almost unique in that it can deform rapidly under geological conditions, reacting on slopes ≤0.58 dip and behaving much like a viscous fluid. Salt has a negligible yield strength and so is easy to deform, principally by differential sedimentary or tectonic loading. Significant differences in rheology and behavioural characteristics exist between the individual evaporitic deposits. Wet salt deforms largely by diffusion creep, especially under low strain rates and when differential stresses are low. Basins that contain salt therefore evolve and deform more complexly than basins where salt is absent. The addition of halokinetic processes to the geodynamic history of a basin can lead to a plethora of architectures and geometries. The rich variety of resultant morphologies have considerable economic as well as academic interest. Historically, salt has played an important role in petroleum exploration since the Spindletop Dome discovery in Beaumont, Texas in 1906. Today, much of the prime interest in salt tectonics still derives from the petroleum industry because many of the world’s largest hydrocarbon provinces reside in salt-related sedimentary basins (e.g. Gulf of Mexico, North Sea, Campos Basin, Lower Congo Basin, Santos Basin and Zagros). An understanding of salt and how it influences tectonics and sedimentation is therefore critical to effective and efficient petroleum exploration. Within rift basins in particular, salt is seen to orchestrate the petroleum system. Through halokinesis it creates structural traps, counter-regional dips on continental margins, and it can carry or entrain adjacent lithologies via rafting. Salt influences synand post-kinematic sediment dispersal patterns and reservoir distribution and can therefore be important for the creation of stratigraphic traps. It can also form top and side seals to hydrocarbon accumulations and act as a seal to fluid migration and charge at a more regional scale. Salt may also dramatically affect the thermal evolution of sediments due to its high thermal conductivity. A thick layer of salt cools sediments that lie below it while heating sediments above it. This effect cannot be underestimated as it helps provide the favourable conditions for source rock maturation in the deepwater Gulf of Mexico and Santos basins, even though sedimentary overburden may be 5 km or more in thickness. Salt can also impact reservoir quality. The role of salt in the diagenetic history of reservoirs through its control on hydrothermal pore waters is a crucial element in the risking of the deepwater Palaeogene play of the Gulf of Mexico, for example. Salt continues to kinetically evolve through time, not only by the classical roller-diapir-pedestal-canopy/ collapse progression but also with varying rates of deformation, in response to changing sedimentation rates and patterns. The relative timing of salt movement and its impact on source, reservoir, trap, seal and timing often governs the prospectivity in saltrelated basins. Beyond the realm of petroleum, salt is also used as a resource for potash, gypsum and nitrates and has the potential to be employed as a repository for radioactive waste or a top seal to sequestered CO2.

Hysteresis of Capillary Pressure, Resistivity Index and Relative Permeability in Different Carbonate Rock Types

Abstract: Experimental measurements of capillary pressure, resistivity index and relative permeability display hysteresis manifested through the dependence of these properties on the saturation path and saturation history whenever fluid saturations undergo cyclic processes. At the pore scale, hysteresis is typically influenced by contact-angle hysteresis, trapping of one phase by another and wettability changes. A laboratory study was conducted to investigate hysteresis effects measured on reservoir core plugs for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering reservoir rock types (RRT) were selected based on whole-core and plug X-ray CT, high-pressure mercury injection, porosity, permeability and thin-section analyses. Primary drainage and imbibition capillary pressure and resistivity index (PcRI) were measured by the porous-plate method using stock tank oil and simulated formation brine at reservoir temperature and overburden conditions. Large hysteresis effects were obtained between primary drainage and imbibition for both Pc and RI curves. Low residual oil saturations (Sor) were measured at the end of forced imbibition indicating oil-wet to mixed-wet characteristics. Nonlinear RI curves were found during imbibition which could not be described by conventional Archie equation. Water-oil relative permeability curves were measured on similar reservoir core samples by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. Hysteresis effects on both oil and water curves were observed between primary drainage and imbibition, and appear to be influenced by the sample rock type involved (i.e. wettability and pore structure). The strong hysteresis in RI was explained by a fluid invasion behavior at the pore level, and was attributed to varying displacement mechanisms between primary drainage and imbibition. Conventional assumption of Archie behavior is therefore not always valid for such carbonate rock types. This RI hysteresis, together with the variation of Kr hysteresis trends with different rock types, may help improve the current hysteresis models and provide better understanding of the hysteresis phenomena in natural porous media.

The Prediction of Permeability From Well Logging Data Based on Reservoir Zoning, Using Artificial Neural Networks in One of an Iranian Heterogeneous Oil Reservoir

Abstract: The distinct characteristics of Iranian oil reservoirs, such as high pressure, heterogeneity and anisotropy, high thickness, carbonation, huge size, and presence of cracks and various rock types, lead to deficiency of present applications of neural network methods. The authors attempt to improve the proficiency of present methods in one of Iranian heterogeneous oil reservoirs for permeability prediction using the well logging data, by zoning the reservoir on the basis of geology characteristics and sorting the data in correspondence. The obtained results from the well logging data using artificial neural networks are compared with the measured permeability in core analysis experiments. The appropriate compatibility of the results confirms the proposed method.

Gas Chromatograph Applications in Petroleum Hydrocarbon Fluids

Abstract: In the petroleum hydrocarbon fluids, the most commonly found molecules are alkanes (linear or branched paraffins), cycloalkanes (naphthenes), aromatic hydrocarbons, or more complicated compounds like asphaltenes. Under surface pressure and temperature conditions, lighter hydrocarbons such as CH4, C2H6, and inorganic compounds such as N2, CO2, and H2S occur as gases, while pentane and heavier ones are in the form of liquids or solids. However, in petroleum reservoir the proportions of gas, liquid, and solid depend on subsurface conditions and on the phase diagram (envelop) of the petroleum mixture. To obtain compositions of a reservoir fluid, a reservoir sample is flashed into gas and liquid phases at ambient conditions. The volume of the flashed gas, and the mass, molar mass and density of the flashed liquid are measured. Then a gas chromatograph is used to analyze compositions of the gas and liquid phases as described briefly below. The recombined compositions based on the gas and liquid according to the measured gas/oil ratio are those of the reservoir fluid.

Control Factors and Diversities of Phase State of Oil and Gas Pools in the Kuqa Petroleum System

Abstract: Based on the analysis of the hydrocarbon geochemical characteristics in the Kuqa petroleum system of the Tarim Basin, this study discusses the causes and controlling factors of the phase diversities and their differences in geochemical features. According to the characteristics and differences in oil and gas phase, the petroleum system can be divided into five categories: oil reservoir, wet gas reservoir, condensate gas-rich reservoir, condensate gas-poor reservoir and dry gas reservoir. The causes for the diversities in oil and gas phases include diversities of the sources of parent material, maturity of natural gas and the process of hydrocarbon accumulation of different hydrocarbon phases. On the whole, the Jurassic and Triassic terrestrial source rocks are the main sources for the hydrocarbon in the Kuqa Depression. The small differences in parent material may cause diversities in oil and gas amount, but the impact is small. The differences in oil and gas phase are mainly affected by maturity and the accumulation process, which closely relates with each other. Oil and gas at different thermal evolution stage can be captured in different accumulation process.

Method for judging wettability of reservoir rock

Abstract: The invention provides a method for judging the wettability of a reservoir rock. The method comprises the following steps of: measuring free relaxation time of oil and water respectively; measuring transverse relaxation time of the oil and the water in saturated states respectively; measuring a nuclear magnetic resonance signal of the reservoir rock in the co-presence of an oil phase and a water phase by using nuclear magnetic resonance technology and recording an oil saturation value and a water saturation value in the co-presence of the oil phase and the water phase; dipping the rock core of the reservoir rock in the co-presence of the oil phase and the water phase in more than or equal to 20,000 ppm paramagnetic solution, waiting for at least 48 hours and separating the nuclear magnetic resonance signal of the reservoir rock in the co-presence of the oil phase and the water phase to obtain the transverse relaxation time of the oil and the water reflecting the size of an oil wet area and a water wet area; and calculating a wettability index in the co-presence of the oil phase and the water phase according to the free relaxation time of the oil and the water, the transverse relaxation time of the oil and the water in the saturated states, the transverse relaxation time of the oil and the water, the oil saturation value and the water saturation value so as to judge the wettability of the reservoir rock.

The Geology of the Arbuckle Group in the Midcontinent: Sequence Stratigraphy, Reservoir Development, and the Potential for Hydrocarbon Exploration

Abstract: The Arbuckle Group of the midcontinent comprises the mid-southern part of the great American carbonate bank (GACB) and consists mostly of carbonates with a few laterally consistent sandstones. The Arbuckle Group is found in the Anadarko, Ardmore, and Arkoma Basins and surrounding environs in the Texas panhandle, Oklahoma, and Arkansas. These basins represented a significant downwarp associated with early rifting in the area now located in the southern one half of both the states of Oklahoma and Arkansas. Similar to other parts of the GACB, the thick widespread Cambrian–Ordovician Arbuckle Group was deposited as mostly restricted shallow-water marine carbonates. The Arbuckle is a cyclic carbonate dominated by intertidal and shallow subtidal facies. In some areas, supratidal or deeper subtidal facies are observed. The depositional model is represented by an extensive, dominantly regressive, tidal flat with persistent peritidal facies across much of the GACB. These peritidal cycles shallow upward with significant variation in thickness from as thin as 4 ft (1.2 m) to more than 110 ft (33.5 m) thick. Large-scale regional changes in relative sea level may have had a large influence on the type of cycles and sequences that formed during Arbuckle deposition. Arbuckle strata, especially within third-order sequence boundaries, are correlatable across the basin. Within the sequence boundaries, cycles can be further grouped into packages of sequences that are composed mostly of either intertidally or subtidally dominated cycles. Detailed local to regional correlation of the facies bundles can be made with gamma-ray and resistivity logs; however, facies are commonly obscured by a strong diagenetic overprint that makes detailed correlation difficult. Reservoirs in the Arbuckle are complex, and porosity is controlled by original depositional fabric, diagenesis, paleokarst, and fracture overprint. Upper subtidal and lower intertidal facies typically have the depositional fabric most conducive to reservoir development. Diagenetic changes are a continuum that begins with early diagenesis, including hypersaline or evaporative conditions as well as vadose and phreatic conditions, and followed by deep phreatic to late thermal diagenesis. Evidence that porosity formed during multiple diagenetic phases exists. Dolomitization and precipitation events are also evidenced at various levels of the profile. Dolomite is the most abundant mineral and can be subdivided into early (syngenetic to penecontemporaneous) hypersaline dolomite, shallow burial mixed-water (phreatic) dolomite, and deeper burial to thermal (baroque and xenotopic) dolomite. The super-Sauk unconformity is recognized as evidence of a eustatic sea level drop and has been used to mark the boundary between the Sauk and Tippecanoe depositional megasequences. The Arbuckle Group contains multiple unconformities at major sequence boundaries. Paleokarst is especially prevalent beneath the super-Sauk unconformity, especially along major sequence boundaries with related unconformity surfaces. Paleokarstic features in the Arbuckle Group have been identified in outcrop in the Arbuckle Mountains of southern Oklahoma and in the southern Ozark uplift in northeastern Oklahoma. Numerous cores and logs indicate collapse breccias that are interpreted to have formed in response to karst conditions. The Arbuckle Group is an important petroleum reservoir in the midcontinent, and has great potential especially for natural gas. Exploration is enhanced by understanding the complex relationships of depositional processes, stratigraphic relationships, paragenesis, and structural overprints. Reservoir development is typically along sequence boundaries, especially where facies have strong diagenetic overprints from dolomitization and dissolution associated with paleokarstic events. No major source rocks exist below or within the Arbuckle Group, so the best reservoirs are structurally related with strong fracture overprints and juxtaposed with source rocks or are along migration pathways.

Variations in Bounding and Scanning Relative Permeability Curves with Different Carbonate Rock Types

Abstract: Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends because of variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir. A detailed laboratory study was performed to investigate relative permeability behavior for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering five reservoir rock types (RRTs) were identified on the basis of whole core and plug X-ray computed tomography (CT), nuclear magnetic resonance (NMR) T2, mercury injection capillary pressure (MICP), porosity, permeability, and thin-section analyses. Primary-drainage (PD) and imbibition water/oil relative permeability (bounding) curves were measured on all the five rock types by the steady-state (SS) technique by use of live fluids at full reservoir conditions with in-situ saturation monitoring (ISSM). Imbibition relative permeability experiments were also conducted on the main RRT samples to assess the relative permeability (scanning) curves in the transition zone (TZ) by varying connate-water saturations. Hysteresis effects were observed between PD and imbibition cycles, and appeared to be influenced by the sample rock type involved (i.e., wettability and pore geometry). Variations in relative permeability within similar and different rock types were described and understood from local heterogeneities present in each individual sample. This was possible from dual-energy (DE) CT scanning and high-resolution imaging. Different imbibition trends from both oil and water phases were detected from the scanning curves that were explained by different pore-level fluidflow scenarios. Relative permeability scanning curves to both oil and water phases increased with higher connate-water saturation. Relative permeability to oil was explained on the basis of the occupancy of the oil phase at varying connate-water saturations. The change in the water relative permeability trend was addressed on the basis of the connectivity of water at the varying connatewater saturations. These results and interpretations introduced an improved understanding of the hysteresis phenomena and fluidflow behavior in the TZ of a Cretaceous carbonate reservoir that can assist in the overall reservoir modeling and well planning.

Chapter 6 – Wettability

Abstract: Publisher Summary The wettability of a rock–fluid system is an overall average characteristic of a heterogeneous system with microscopic relative wetting throughout the porous medium. The rock pore surfaces have preferential wetting tendencies toward water or oil leading to establishment of the various states of overall wettability. This overall wettability has a dominant influence on the fluid flow and electrical properties of the water-hydrocarbon-rock system. It controls the capillary pressure and relative permeability behavior, and thus the rate of hydrocarbon displacement, and ultimate recovery. The chemical compositions of the fluids and the rock surfaces determine the values of the solid–fluid and fluid–fluid specific surface energies. Thus, the mineralogy of the rock surface has an influence on the relative adhesive tensions and contributes to the overall wettability of the fluid–rock system. Polar organic compounds in crude oil can react with the surface, forming a preferentially oil-wet surface. Interfacially active compounds—those that tend to accumulate at the interface—can lower the interfacial tension and affect the wetting characteristics of the fluid–rock system. Evaluation of relative water/oil wetting of porous rocks is a very important aspect of petroleum reservoir characterization. Wettability has a decisive influence on oil production rates, the water/oil production ratio after water breakthrough, the oil production rates of enhanced oil production technologies, and the residual oil saturation of a reservoir at abandonment.

Dim spots: Opportunity for future hydrocarbon discoveries?

Abstract: When water in the pores of a reservoir rock is replaced by hydrocarbon, the acoustic impedance universally reduces. When the reservoir becomes more porous, the impedance reduces further. When net-to-gross ratio (for most reservoirs) increases, the average impedance of the reservoir reduces further still. Thus low impedance is prospective. If the prospective reservoir is encased in higher-impedance rock, this produces more contrast and thus a seismic bright spot. If the prospective reservoir is encased in lower-impedance rock, this produces less contrast and thus a seismic dim spot.

The characteristics of dolomite reservoir and trap accumulation in the middle assemblages of Ordovician in Ordos Basin,China

Abstract: The gas exploration of Lower Paleozoic in Ordos Basin has long been focusing on the stratigraphic trap gas reservoirs of paleo-weathering crust at the top of Ordovician.Recently,a further study on the accumulation mechanism of dolomite reservoirs has found new lithologic gas reservoirs in the middle assemblages of Ordovician in the east of the palaeouplift.These reservoirs were mainly developed in the dolomites of the 5th sub-member of 5th member of Majiagou Formation(Ma55),with significantly different characteristics from those of the weathering crust reservoirs at the top of Ordovician.As controlled by sedimentary environment,the Ma55 dolomites in the middle Ordovician assemblages were distributed in a belt of north-south direction.,The dolomite belt in western Jingbian County was close to the palaeouplift with strong hydrodynamic conditions and developed shoal facies,and thus the dolomite products after dolomitization are characterized by vast distribution area,large thickness,pure lithology,and south-north continuous distribution.These dolomites have developed intercrystalline pores and serve as the favorable reservoirs.In the late Caledonian,the uplift of the entire basin led to the denudation of strata in the middle assemblages in the east of the palaeouplift.This allowed the middle assemblages to be in contact with hydrocarbon source rocks in the Upper Paleozoic,thus forming a good source-reservoir relationship.Due to lithofacies variations,the dolomites of shoal facies in the Ma55 of middle assemblages formed lithological traps,thus favoring the gas accumulation.