Reservoir Petrophysical Properties Research Articles

Pore throat size distribution and oiliness of tight sands-A case study of the Southern Songliao Basin, China

In this study, several methods such as mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) for characterizing the pore throat size distribution of tight sandstone reservoirs were selected. The differences of mercury injection parameters such as maximum interconnected pore throat radius, median radius, mercury injection curve, and pore throat distribution curve of oil-bearing and oil-free samples were compared. By designing the algorithm program and using the mercury injection data, the coefficient of converting the T2 relaxation time to the pore-throat radius was corrected, and the pore throat distribution of different oil saturation samples were analyzed. Environmental scanning electron microscope (ESEM) was also used to observe the microscopic pores and the oil in them. Using the above data, we systematically analyzed the control of pore throat distribution on the oiliness. It is found that the oiliness depends on the maximum interconnected pore throat radius, and the oil saturation depends on the oil migration front pressure and pore volume. The oiliness of tight sand has good relationship with pore throat size distribution, and the better reservoir petrophysical properties result in better oiliness. Statistics on the pore throat size distribution of oil-bearing tight sands were carried out and main intervals of pore throat size distribution of oil-bearing reservoirs were given in this paper. This understanding provides a basis for searching sweet spots in the future exploration of the tight oil.

Impacts of petrophysical properties of sandstone reservoirs on their irreducible water saturation: Implication and prediction

Irreducible water saturation (Swir) is an important parameter in reservoir evaluation that can affect hydrocarbon saturation, permeability prediction models and estimation of original oil in - place. The Swir is usually obtained from capillary pressure data. In this study, routine and special core analyses for sandstone reservoirs in four wells were used to investigate the relationship between irreducible water saturation and the petrophysical properties of the reservoir rocks. The results indicated that the magnitude of Swir is controlled by a complex relationship of reservoir rock wettability, reservoir quality, clay content, clay mode of distribution, and capillary pressure. Reservoir rock wettability can obscure the effect of other factors in the case of oil–wet rocks. On the other hand, irreducible water saturation from published data were used together with the studied four wells data, providing 110 sandstone samples covering different geologic ages and facies, to examine the applicability of the traditional empirical models that were commonly used in Swir prediction as well as to introduce a new simple equation by which Swir can be predicted. The study indicated that the Timur equation gave the best applicable empirical model to predict Swir. The study indicated also that the flow zone indicator can slightly improve the prediction strength of the Swir. Using other parameters characterizing capillary pressure curves such as displacement pressure and Swanson parameter didn't improve the relationship prediction strength.

Analysis of Spatial Distribution Pattern of Reservoir Petrophysical Properties for Horizontal Well Performance Evaluation-A Case Study of Reservoir X

Introduction:Building a large number of static models to analyze reservoir performance is vital in reservoir development planning. For the purpose of maximizing oil recovery, reservoir behavior must be modelled properly to predict its performance. This requires the study of the variation of the reservoir petrophysical properties as a function of spatial location.Methods:In recent times, the method used to analyze reservoir behavior is the use of reservoir simulation. Hence, this study seeks to analyze the spatial distribution pattern of reservoir petrophysical properties such as porosity, permeability, thickness, saturation and ascertain its effect on cumulative oil production. Geostatistical techniques were used to distribute the petrophysical properties in building a 2D static model of the reservoir and construction of dynamic model to analyze reservoir performance. Vertical to horizontal permeability anisotropy ratio affects horizontal wells drilled in the 2D static reservoir. The performance of the horizontal wells appeared to be increasing steadily as kv/kh increases. At kv/kh value of 0.55, a higher cumulative oil production was observed compared to a kv/kh ratio of 0.4, 0.2, and 0.1. In addition, horizontal well length significantly affects cumulative oil production of the petroleum reservoir studied.Results:At kv/kh of 0.55, the results of the analysis showed a rapid decrement in cumulative oil production as the horizontal well length decreases. Considering horizontal well length of 3000 ft, 2000 ft, and 1500 ft, a minimum cumulative oil production was obtained from a horizontal well length of 1500 ft.Conclusion:The geostatistical and reservoir simulation methods employed in this study will serve as an insight in analyzing horizontal well performance.

Oil families and inferred source rocks of the Woodford–Mississippian tight oil play in northcentral Oklahoma

Twenty-four oils produced from the Woodford Shale and overlying Mississippian strata in central Oklahoma were characterized geochemically to determine their possible source(s). The 168 core samples from the Woodford and Mississippian sections of 14 wells in central Oklahoma were initially characterized by total organic carbon (TOC), Rock-Eval, and vitrinite reflectance, and select samples (TOC > 1.0 wt. %) were subjected to biomarker analyses to characterize source input, depositional environment, maturity, and oil-to-source rock correlations. Thermal maturity parameters indicate the Woodford Shale is immature to marginally mature in Payne County, Oklahoma, and shows a progressive increase in maturity toward the southwest. Close to the Nemaha uplift, the Woodford is in the main stage of oil generation. It is proposed that the oils in this area have three possible origins: (1) Oils produced from the Woodford and overlying Mississippian strata have similar fingerprints, suggesting the Woodford Shale and overlying Mississippian strata are in communication; (2) oils produced near the Nemaha uplift (Logan and western Payne Counties) were sourced from the Woodford but had a significant Mississippian source contribution based on source-specific biomarkers; (3) oils east of the Cherokee platform (eastcentral Payne County) share strong Woodford source characteristics, and they were not generated in situ from the immature Woodford Shale but probably migrated from the Woodford Shale in the deeper part of the Anadarko Basin in southern Oklahoma. These results are consistent with the findings that indicate abundant marine coarse-grained biogenic silica (radiolarian-rich) chert facies found in eastcentral Payne County may contribute to good reservoir petrophysical properties, suggesting the Woodford Shale may not be a source in this area but simply a tight reservoir.

ТИПИЗАЦИЯ РАЗРЕЗОВ КОНТИНЕНТАЛЬНЫХ ОТЛОЖЕНИЙ КАК ОСНОВА ПОСТРОЕНИЯ ФАЦИАЛЬНЫХ МОДЕЛЕЙ ПО ДАННЫМ ДИНАМИЧЕСКОЙ ИНТЕРПРЕТАЦИИ СЕЙСМИЧЕСКИХ ДАННЫХ МОГТ 3D

The article is devoted to the prediction of reservoirs in continental sediments on the basis of combining the results of dynamic interpretation of 3D seismic data and facies modeling. It is believed that the direct carrier of information about the petrophysical properties of reservoirs and their power are the results of drilling. However, in the territory of the Uvat district at the prospecting stage of exploration drilling volume is very limited and maps of effective thicknesses are calculated based on the results of dynamic interpretation of seismic data. Often such maps have errors of up to 5 m or more, so this forecast is always controlled by facies conditions, built according to the core and geophysical studies of wells. In order to correctly compare the forecast of reservoirs according to geological and seismic data, the article proposes an approach to the typification of continental sediment sections, which shows that each type of section is characterized not only by a certain set of sand lithotypes with different filtration and capacitive properties, but also by certain total reservoir thicknesses. The use of this approach allows us to construct facies models of continental sediments adequate to the texture data, and to correctly compare the distribution of reservoirs by seismic data.

Formation pressure and fluid flow measurements in marine gas hydrate reservoirs, NGHP-02 expedition, offshore India

Abstract Open Hole Modular Dynamic Testing (MDT) measurements were conducted in a gas hydrate-bearing sand-rich reservoir offshore India during the National Gas Hydrate Program 02 (NGHP-02) Expedition. The primary goal of this test was to obtain effective reservoir petrophysical properties in the presence of gas hydrates. The test plan included a series of pre-hydrate dissociation flow and build-up (shut-in) tests, and an attempt to dissociate gas hydrate in a sand-rich reservoir by depressurization to collect formation fluid samples and to further characterize in situ gas hydrate stability conditions. Schlumberger's wireline MDT tool was used in a dual-packer configuration to isolate the formation being tested. This paper presents the results of the open hole MDT measurements that were conducted in Hole NGHP-02-23-C in Krishna-Godavari Basin at a water depth of 2553.5 m. The MDT dual packer test was conducted in 27 cm (10.63 in) diameter open hole section of the borehole within a 1-m interval isolated between two inflatable packers with the midpoint of the test interval at 2853.0 m below rig floor (mbrf) (271.0 m below sea floor (mbsf)). This was the first gas hydrate MDT test ever conducted in ultradeep water to characterize a gas hydrate reservoir system. Pre-hydrate dissociation testing was performed with a drawdown period (depressurization) of 20 min followed by a build-up (shut-in) of 20 min. The measured formation pressure was 4090.7 psia and the formation fluid (i.e., water) mobility was calculated at 1.98 mD/cP. During the second dissociation phase of the same test a maximum pressure drawdown of 840 psia was achieved; however, falling short of the 1120 psia drawdown required for dissociation. During the dissociation test the flow line pressure stabilized at a flowing pressure of 3250 psia which can be attributed to the relatively high mobility of the free water phase in the hydrate-bearing reservoir. Good quality formation pressure and near well bore mobility data was acquired that yielded a “high confidence” reservoir effective radial permeability-thickness product of 0.2 mD.m (or a horizontal effective permeability of 0.1 mD assuming a reservoir thicknees of 1.8 m) using pressure transient analysis (radial flow regime was achieved) despite unstable borehole conditions and complex operations in these shallow unconsolidated sedimentary sections.

Application of medical and dental CT-Scan technologies for determining porosity distribution of the Persian Gulf coastal zone and Zagros basin core samples

Comprehensive study of a reservoir is possible through a correct and accurate analysis of reservoir petrophysical properties and their distribution pattern in geological formations. Application of imaging technology assists a careful analysis of petrophysical properties without destroying samples. In this study, medical and dental CT-scan techniques are applied for porosity determination of 20 core samples collected from Persian Gulf coastal zone and Zagros basin in order to compare with routine porosity measurement technique. The studied core samples included salt, sandstone, marl, calcite-carbonate and dolomite-carbonate collected from Gachsaran, Aghajari, Dalan, Asmari and Kangan Formations in Zagros basin. To obtain average porosity for each sample digital rock images were obtained using dental and medical CT-scan techniques and analyzed through image processing. In addition, average porosity was determined using nitrogen porosimetry and compared with imaging measurements. Results showed a considerable agreement between CT-scan techniques and average routine porosity method. However, the high-resolution dental CT-scan technique is superior to medical CT-scan technique for porosity determination through image analysis. Moreover, CT-scan responded well for sandstone and calcite-carbonate rocks, but not sufficient to evaluate dolomite-carbonate, marl and salt rocks.

Reservoir Characterization Through Target-Oriented AVA-Petrophysical Inversions with Spatial Constraints

We apply three methods that use different regularization strategies to insert spatial constraints into the seismic-petrophysical inversion. The first method is what we call the structurally constrained inversion (SCI), which directly uses the structural information brought by the seismic stack image to insert geological (structural) constraints into the inversion. The second method is based on anisotropic Markov random field (AMRF) and uses the Huber energy function to reasonably model the spatial heterogeneity of petrophysical reservoir properties. Finally, the last method includes both geostatistical information (describing the lateral variability of reservoir properties) and hard data (i.e. well log data) constraints into the inversion kernel (GHDC inversion). For computationally feasibility, we apply a target-oriented inversion that uses the amplitude versus angle (AVA) responses extracted along the top reservoir reflections to infer the petrophysical properties of interest (i.e. porosity, water saturation and shaliness) for the target layer. In particular, an empirical, linear rock-physics model, properly calibrated for the investigated area, is used to rewrite the P-wave reflectivity equation as a function of the petrophysical contrasts instead of the elastic constants. This reformulation allows for a direct and a simultaneous estimation of petrophysical properties from AVA data. The implemented approaches are tested both on synthetic and field seismic data and compared against the standard method in which each AVA response is inverted independently (laterally unconstrained Bayesian inversion; LUBI). In the case of poor signal-to-noise ratio it turns out that the three considered spatially constrained methods achieve better delineations of reservoir bodies and provide more reliable results than the standard LUBI approach. More in detail, the AMRF recovers sharper geological boundaries than the SCI and GHDC algorithms. The SCI algorithms is more sensitive to data noise, whereas the key advantage of the GHDC consists in analytically providing posterior uncertainties for the model parameters. Finally, for what concerns the computational cost the GHDC and the SCI methods result the most and the least computationally demanding, respectively.

Factors controlling reservoir properties and hydrocarbon accumulation of the Eocene lacustrine beach-bar sandstones in the Dongying Depression, Bohai Bay Basin, China

Abstract Lacustrine beach-bar sandstone reservoirs are economical important exploration targets in the Dongying Depression, Bohai Bay Basin. The factors that controls reservoir quality and hydrocarbon accumulation in lacustrine beach-bar sandstones were systematically investigated through an integrated petrographic, petrophysical, and diagenesis analysis. The reservoir properties of the beach-bar sandstones are mainly affected by compaction, carbonate cementation and dissolution. Significant negative relationships exist between both the porosity and permeability and the volume of carbonate cement. Carbonate cement is mainly distributed along the sandstone-mudstone contacts. Sandstones with thicknesses less than 1 m are generally tightly cemented to form zones with low petrophysical properties. The material source of the carbonate cement in the tightly cemented zone was highly likely from the interbedded mudstone. Content of carbonate cements in the center of the thick sandstones is low, whereas compaction is the dominant diagenetic process, with some dissolution. There is a positive correlation between the petrophysical properties of the beach-bar sandstones and the content of kaolinite. The petrophysical properties have an inverse correlation with the contents of illite and illite-smectite mixed-layer clays. Reservoir petrophysical property largely controls hydrocarbon accumulation in the beach-bar sandstones. Compared with non-oil bearing sandstones, oil-bearing sandstones have higher porosity and a larger pore-throat size. Sandstones with a porosity of less than 8.5% and/or low permeability of less than 1.02 × 10−3 μm2 are mostly incapable of accumulating oil.

Estimating petrophysical reservoir properties through extended elastic impedance inversion: applications to off-shore and on-shore reflection seismic data

Estimating petrophysical reservoir properties through extended elastic impedance inversion: applications to off-shore and on-shore reflection seismic data

Reservoir characteristics of the Kuhlan sandstones from Habban oilfield in the Sabatayn Basin, Yemen and their relevance to reservoir rock quality and petroleum accumulation

Integrated petrophysical and petrographic analyses were performed on the Kuhlan clastic rocks to evaluate the petrophysical reservoir properties, identify grain sorting along with the clay type and mineral volumes using well logs coupled with core data. Core samples were collected from two key wells and their results were used to determine the reservoir properties and bulk mineralogical composition and, additionally, to calibrate the well log results from three un-cored to the two cored wells.The Kuhlan clastic reservoir rocks have porosity values between 6% and 12%. These porosity values are mainly intergranular primary and secondary porosity. Permeability is likewise variable with values in the range of 78–304 mD. The Kuhlan reservoir rocks also have high hydrocarbon saturation exceeding 70%, with relatively high movable oil. These reservoir properties are achieved from log-derived and core porosity and permeability results.The lithology and mineral composition of the well logs and petrographic studies in this study indicate that the Kuhlan sandstone can be considered as an alternative reservoir rock in the basin. The Kuhlan Formation is primarily composed of sandstone that contains quartz, feldspar (i.e., orthoclase, plagioclase (albite) minerals and illite, and calcite cements. The quartz mineral is dominant followed by feldspar as the second most abundant mineral in this formation. The Kuhlan Formation sandstones are classified (based on standard rock classification schemes) into arkose, sub-arkose and feldspathic lithofacies. The results of petrographic analysis also indicate a continental block transitional source of the Kuhlan Formation sandstones. Petrographically, the Kuhlan sandstones are poorly sorted and range from fine to coarse-grained and contain high percentages of detrital quartz and feldspar-rich grains with a significant amount of rock fragments. The Kuhlan sandstones also contain a variable range of matrix and cement contents.Based on the results of this study, the reservoir quality of the Kuhlan sandstone ranges between good to poor reservoir quality. The Kuhlan Formation has arkosic and sub-arkosic sandstones that result in a good reservoir quality with a significant increase of the permeability and intergranular porosity. This is attributed to the coarse-grained texture, high percentages of detrital quartz, slightly well sorted texture and the low degree of matrix and cements. In contrast, the Kuhlan Formation feldspathic sandstone has poor reservoir quality due to the poor sorting texture, pore space occluding clayey groundmass, and carbonate cement.

Pore characterization and clay bound water assessment in shale with a combination of NMR and low-pressure nitrogen gas adsorption

Pore size distribution (PSD) and the volume of clay bound water (CBW) are crucial parameters for gas shale reservoirs formation evaluation. Low-field nuclear magnetic resonance (LF-NMR) has been extensively applied to characterize petrophysical properties of reservoirs. However, limited understanding remains for unconventional shales. Defining NMR T2 cutoff to differentiate CBW from free water is a challenge in shales since conventional approach, such as using centrifuge, is not feasible to completely remove free water in tight shales. Thermal treatment is therefore suggested for further extraction of movable pore water, however, the influence of temperature on nanoscale pore structure and clay mineralogical composition has been underestimated in previous studies and thus requires further investigation.This paper re-defines the critical dehydration temperature for accurate PSD interpretation in Permian Carynginia shale, Western Australia to determine T2 cutoff for CBW. By using low-pressure N2 gas adsorption (LP-N2-GA) in parallel with LF-NMR, we identified a striking anomalous PSD consistency for critical temperature detection and verification. Our results shows that movable pore water can be maximally removed around 80 °C (75 °C), while the sensitive clay, CBW and microstructure are well-preserved for accurate petrophysical evaluation. Clay mineral conversion would occur when temperatures are higher than 80 °C, while temperatures lower than 75 °C would induce large misinterpretations for nanopore structure. Our recommended scheme could provide a potential adaptability for the formation evaluation of Permian Carynginia shale in the downhole practices.

Petrophysical Properties of the Upper Qamchuqa Carbonate Reservoir through Well Log Evaluation in the Khabbaz Oilfield

Khabbaz oilfield has a symmetrical subsurface anticline with a length of 20 km and a width of 4 km. Despite the fact that Khabbaz oilfield has a small size structure, it is known as one of the massive Oilfields in Iraq. The reservoirs of Khabbaz oilfield are produced by both Cretaceous and Tertiary rocks. The Upper Qamchuqa reservoir is the most productive reservoir of the Khabbaz oilfield with thickness ranges between 138 to 170 m. This formation is subdivided into two units, from the top is Unit A with a thickness of 67 m and from the bottom is Unit B with a thickness of 84.5 m. From a full set of log data of three wells (Kz-1, Kz-13 and Kz-14), the petrophysical properties of Khabbaz oilfield has been evaluated. The wireline log data includes gamma-ray log, sonic log, neutron log, density log and resistivity logs, both Rxo and Rt logs. This study revealed that Unit A represents the best reservoir characteristics where Unit A is subdivided into six reservoir subunits named (1-A, 2-A, 3-A, 4-A, 5-A and 6-A). They are separated by five non-reservoir subunits named 1-N, 2-N, 3-N, 4-N and 5-N. In addition to a less porous reservoir unit that is called Unit B, which has been divided into four reservoir subunits named 1-B, 2-B, 3-B and 4-B. These are separated by five non-reservoir units named 1-N, 2-N, 3-N, 4-N and 5-N. It has been recognized that both reservoir units A and B are clean formations and have minimum shale volume with high porosity in limestone and dolomite to dolomitic limestone lithology with high oil saturation and low water saturation. Based on the above reservoir characteristics it can be concluded that the reservoir units of the Khabbaz oilfield contain a massive commercial hydrocarbon accumulation.

Probabilistic estimation of reservoir properties by means of wide-angle AVA inversion and a petrophysical reformulation of the Zoeppritz equations

We apply a target-oriented amplitude versus angle (AVA) inversion to estimate the petrophysical properties of a gas-saturated reservoir in offshore Nile Delta. A linear empirical rock-physics model derived from well log data provides the link between the petrophysical properties (porosity, shaliness and saturation) and the P-wave, S-wave velocities and density. This rock-physics model, properly calibrated for the investigated reservoir, is used to re-parameterize the exact Zoeppritz equations. The so derived equations are the forward model engine of a linearized Bayesian AVA-petrophysical inversion that, for each data gather, inverts the AVA of the target reflections to estimate the petrophysical properties of the reservoir layer, keeping fixed the cap-rock properties. We make use of the iterative Gauss-Newton method to solve the inversion problem. For each petrophysical property of interest, we discuss the benefits introduced by wide-angle reflections in constraining the inversion and we compare the posterior probability distributions (PPDs) analytically obtained via a local linearization of the inversion with the PPDs numerically computed with a Markov Chain Monte Carlo (MCMC) method. It results that the porosity is the best resolved parameter and that wide-angle reflections effectively constrain the shaliness estimates but do not guarantee reliable saturation estimates. It also results that the local linearization returns accurate PPDs in good agreement with the MCMC estimates.

3D Reservoir Modeling of Triassic Yanchang Formation Chang 812 Layer in Honghe36 well area, Ordos Basin, China

Background: Three-dimensional geological modeling of reservoirs is not only the key factor for reservoir description and prediction of oil reserves but also an important means of quantitative characterization of reservoir geometry and heterogeneity in three dimensional spaces. The aim of this paper is to establish prediction model for sandstone classification and reservoir petrophysical properties. Methods: Sand body prediction model was built by using stochastic simulation of discrete variables. Gauss model and sequential Gauss simulation method were selected to build porosity, permeability and oil saturation models. Results: The Chang 812 layer includes three sedimentary microfacies: distributary channel, inter-distributary bay and swamp. The dominant thickness of Chang 812 layer ranges from 15 to 20m. Three other classes of thickness (5-10 m, 10-15 m and 0-5 m) are subsequently less present. The major porosity of Chang 812 layer ranges from 5 to 15%, the major permeability ranges from 0.1 to 2×10-3μm2 and the major oil saturation ranges from 55 to 70%. Conclusion: The Chang 812 layer of Triassic Yanchang Formation mainly formed in braided delta plain depositional environment. The truncated Gauss simulation of sand body was applied in simulation. The thickness of the sand body is relatively greater than the porosity, permeability and oil saturation values.

Petrophysical Analysis of E5 sand group of Sokor Formation, Termit Basin, Niger

The main objective of well logging is to estimate the petrophysical properties of reservoirs which includes porosity and hydrocarbon saturation for hydrocarbon exploration and production purposes. This paper portrays the result of a wireline log study on the E5 sand group of Sokor Formation of the Paleogene in Termit Basin. The objectives of this research are to differentiate the log characteristics of the sediment in the Sokor Formation and provide a preliminary result of the porosity, permeability and hydrocarbon saturation of the study area. A total number of 3 wells were fully evaluated for this research. A compilation of wirelines data sets availability which includes calliper log, gamma ray log (GR), neutron log (NPHI), density log (RHOB) and resistivity logs (RD and RS) were carefully analysed during this study. Petrophysical analysis reveals that the E5 sand group of Sokor Formation has a very high porosity of up to 28.7% and high hydrocarbon saturation up to 88.7%. The suggests future work should include the integration of well log analysis with core analysis.

Porosity estimation in the Fort Worth Basin constrained by 3D seismic attributes integrated in a sequential Bayesian simulation framework

The accurate inference of reservoir properties such as porosity and permeability is crucial in reservoir characterization for oil and gas exploration and production as well as for other geologic applications. In most cases, direct measurements of those properties are done in wells that provide high vertical resolution but limited lateral coverage. To fill this gap, geophysical methods can often offer data with dense 3D coverage that can serve as proxy for the variable of interest. All the information available can then be integrated using multivariate geostatistical methods to provide stochastic or deterministic estimate of the reservoir properties. Our objective is to generate multiple scenarios of porosity at different scales, considering four formations of the Fort Worth Basin altogether and then restricting the process to the Marble Falls limestones. Under the hypothesis that a statistical relation between 3D seismic attributes and porosity can be inferred from well logs, a Bayesian sequential simulation (BSS) framework proved to be an efficient approach to infer reservoir porosity from an acoustic impedance cube. However, previous BBS approaches only took two variables upscaled at the resolution of the seismic data, which is not suitable for thin-bed reservoirs. We have developed three modified BSS algorithms that better adapt the BSS approach for unconventional reservoir petrophysical properties estimation from deterministic prestack seismic inversion. A methodology that includes a stochastic downscaling procedure is built and one that integrates two secondary downscaled constraints to the porosity estimation process. Results suggest that when working at resolution higher than surface seismic, it is better to execute the workflow for each geologic formation separately.

Combining basin modelling with high-resolution heat-flux simulations to investigate the key drivers for burial dolomitization in an offshore carbonate reservoir

The Eocene El Garia Formation in the offshore Hasdrubal Field was originally a nummulitic limestone in which subsequent burial dolomitization has significantly enhanced permeability. Identification of the reservoir's petrophysical property distributions requires knowledge of the spatial extent of its dolomitization, in turn requiring understanding of the processes that caused the dolomitization. Some of this understanding can be derived from measurements but others need to be simulated. In this study, the former are used as guides and we focus on the latter, evaluating the character of the dolomitizing fluid's movement and temperature patterns by using basin modelling to develop heat-flux simulations to represent the time of dolomitization. Basin modelling reconstructs the region's geology at the time of dolomitization, while heat-flux simulations recreate the appropriate conductive and convective heat and mass transport through these systems. Potential key drivers are rock mass and fault-zone permeability, and the position and shape of any salt domes. The results suggest that salt dome shape and position is the dominant control, the salt dome localizing convective systems which also use convenient faults so that hotter upwelling fluids pass through the Hasdrubal reservoir and are instrumental in the development of burial dolomitization.

Fluid–rock interactions during continuous diagenesis of sandstone reservoirs and their effects on reservoir porosity

AbstractThe Cretaceous sandstone reservoir in the Kuche Depression, Tarim Basin, western China, was investigated with reference to its reservoir property evolution during diagenesis. Six general diagenetic stages were recognized through petrographic, mineralogical and geochemical analyses. Fluid–rock interaction experiments were conducted under these six continuous diagenetic conditions, that is with a simulation sequence of compaction → early diagenesis → organic acid incursion I → elevated temperature/pressure → organic acid incursion II → late diagenesis. Corresponding to these six experimental stages, a total of six models were constructed. Finally, an extended model of fluid–rock interaction during diagenesis at a geological timescale (from 30 Ma to present) was constructed after various parameters had been validated. Results demonstrate that the diagenetic stages from both the experimental and numerical simulations generally matched findings obtained from the petrographic and geochemical analyses: (i) With compaction becoming weakened, cementation by various minerals was gradually increased. (ii) Quartz overgrowth occurred because the contemporaneous sedimentary water was alkaline. (iii) Most minerals (for example, calcite and feldspar minerals) displayed dissolution owing to the first organic acid incursion, resulting in the visual porosity increasing to 29·26%. (iv) Increases in temperature and pressure caused a minor fluctuation of the porosity change. (v) The cement that formed during earlier stages largely dissolved with the second organic acid incursion. (vi) During the last stage, the reservoir fluid was diluted by sedimentary alkaline water and most minerals precipitated under an alkalic environment. The present porosity simulated is about 11·4%, comparable with the actually measured data. This study demonstrates that the combination of petrographic observations, laboratory experiments and numerical simulations can not only reconstruct the diagenetic process, but also provide a quantitative evaluation and prediction of reservoir petrophysical properties.

Experimental and Numerical Studies of CO2 EOR in Unconventional Reservoirs

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 179634, “Experimental and Numerical Studies of CO2 EOR in Unconventional Liquid Reservoirs With Complex Fracture Networks,” by Jianlei Sun, SPE, Amy Zou, and David Schechter, SPE, Texas A&M University, prepared for the 2016 SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. The paper has not been peer reviewed. This study investigates oil-production mechanisms from the matrix into the fracture by simulating two laboratory experiments as well as several field-scale studies and evaluates the potential of using carbon dioxide (CO2) huff ’n’ puff to enhance oil recovery in unconventional liquid reservoirs (ULRs) with nanodarcy-range matrix permeability and complex natural-fracture networks. This study explores the mechanisms contributing to oil recovery with numerical modeling of experimental work and investigates the effects of various parameters on oil recovery. Introduction CO2 injection has been recognized as one of the more important and successfully applied enhanced-oil-recovery (EOR) processes in the US since the start of the first commercial CO2-injection project in 1972. Statistics show that, out of the 153 active CO2 EOR projects worldwide, 139 of them are in the US. CO2 flooding is the only EOR method in the US that has been consistent and economical since the drop in oil prices in the 1980s. One of the main advantages of CO2 injection is that CO2 can achieve miscibility with the resident hydrocarbon when minimum miscibility pressure (MMP) is attained. Although CO2 flooding has demonstrated the potential of increasing oil production in conventional reservoirs, if this EOR process were to be applied to ULRs, the oil-recovery mechanism could not be considered the same as that during a conventional CO2 flooding because of the differences in reservoir petrophysical properties, fluid-phase behavior, and the fundamental mass-transfer mechanisms. In general, diffusion during gas injection has been recognized as a critical mechanism that affects the oil recovery in fractured reservoirs. If the diffusive flow in the matrix is being neglected during simulation, the calculated result will underestimate productivity. Furthermore, complex fracture geometry has been proposed for hydraulic fracturing because of the intersection between hydraulic fractures and in-situ natural fractures. Numerous simulation and experimental studies have evaluated production performance of complex fracture networks. However, there is no extensive work regarding the potential of CO2 huff ’n’ puff in complex fracture geometries.