Low Permeability Shale Research Articles

Geochemical and Geological Characterization of Marine‐Continental Transitional Shale: A Case Study in the Ordos Basin, NW China

AbstractThe organic‐rich shale of the Shanxi and Taiyuan Formation of the Lower Permian deposited in a marine‐continental transitional environment are well developed in the Ordos Basin, NW China, which is considered to contain a large amount of shale hydrocarbon resources. This study takes the Lower Permian Shanxi and Taiyuan shale collected from well SL# in the Ordos Basin, NW China as an example to characterize the transitional shale reservoir. Based on organic geochemistry data, X‐ray diffraction (XRD) analysis, field‐emission scanning electron microscopy (FE‐SEM) observations, the desorbed gas contents of this transitional shale were systematically studied and the shale gas potential was investigated. The results indicate that the Lower Permian Shanxi and Taiyuan shale has a relatively high total organic carbon (TOC) (average TOC of 4.9%) and contains type III kerogen with a high mature to over mature status. XRD analyses show that an important characteristic of the shale is that clay and brittle minerals of detrital origin comprise the major mineral composition of the marine‐continental transitional shale samples, while the percentages of carbonate minerals, pyrite and siderite are relatively small. FE‐SEM observations reveal that the mineral matrix pores are the most abundant in the Lower Permian shale samples, while organic matter (OM) pores are rarely developed. Experimental analysis suggests that the mineral compositions mainly govern the macropore development in the marine‐continental transitional shale, and mineral matrix pores and microfractures are considered to provide space for gas storage and migration. In addition, the desorption experiments demonstrated that the marine‐continental transitional shale in the Ordos Basin has a significantly potential for shale gas exploration, ranging from 0.53 to 2.86 m3/t with an average value of 1.25m3/t, which is in close proximity to those of terrestrial shale (1.29 m3/t) and marine shale (1.28 m3/t). In summary, these results demonstrated that the Lower Permian marine‐continental transitional shale in the Ordos Basin has a significantly potential for shale gas exploration.

Geochemical segregation of early Permian, Paleocene and Eocene sediments of Potwar Basin, Pakistan: I Geophysical and isotopic analysis for source and depositional environment

Segregation of sediments for oil and gas potential is a complex task. In this study three oil wells i.e. Dhurnal, Pariwali and Pindori were analyzed for oil and gas potential using geophysical well logs and isotopic analysis. 50 sediments (Eocene to Early Permian) from three productive oil wells were analyzed for source and depositional environment. The Eocene Chorgali limestone and Eocene Sakesar limestone showed good permeability (Spontaneous Potential log) with interbedded shale (Gamma Ray log) while Paleocene Patala and Early Permian Sardhai formation indicated low permeability and good shale presence. Isotopic (13δC and 15δN) and elemental analysis suggested that the source of organic matter was C3 plants with anoxic carbonate depositional setting. Total organic carbon and Rock Eval parameters (S1 and S2) indicated a good quantity of organic matter. Ratio based on Rock Eval parameters indicated the dominant potential for oil expulsion in Paleocene Patala and Early Permian Sardhai formation. Hydrogen index and oxygen index indicated the Type-II/III kerogen as a source of organic matter. The sediments were thermally mature and within the oil expulsion window. Based on results, Eocene Chorgali limestone has a good reservoir while Paleocene Patala shale has a good source rock character.

Time-lapse monitoring of stress-field variations within the Lower Permian shales in Kansas

Azimuthal stress-field variations in Permian shale overlying voids in salt appear related to localized void roof failure based on interpretations of time-lapse recordings of passive seismic surface-wave data. Salt-dissolution voids in south-central Kansas exist within the Hutchinson Salt Member as a result of solution mining operations early in the 20th century. Since shear-wave velocity can be estimated from surface-wave analysis and is directly related to the shear modulus, or material rigidity, it can be used to indicate shale cap-rock competency. Temporal bulk-velocity variations in bedrock acquired over a known void from 2013 to 2018 are consistent with cyclic stress-field behavior expected with repetitive localized failure within the shale cap rock. It was determined that roof failure and associated subsidence began prior to the 2013 surveys along a north–south failure plane with consistent progression from southwest to northeast until 2017. A low-velocity anomaly observed in 2014–2015 on both profiles indicated a load redistribution in the shale cap rock. This low-velocity region was gradually replaced by an increasing velocity field in subsequent years. These bulk-velocity variations are interpreted as representations of stoping, which occurs when overlying roof layers or sidewall segments progressively fail. As of 2018, the velocity trend in the affected area remained lower than the recorded baseline conditions, with no low-velocity anomalies observed since 2015. Shear-wave velocities are not likely to return to 2013 conditions due to loss of roof material and redistribution of load. Annual surveys will monitor for conditions consistent with the beginning of a stress buildup and roof collapse unless monitoring indicates a change in the subsurface that warrants invasive analysis or other actions.

Field experience and numerical investigations of minifrac tests with flowback in low-permeability formations

In this study, flowback-assisted minifrac tests were conducted in low-permeability shale and salt formations to measure the in situ stress. An injection/flowback testing protocol was implemented in each test to achieve accuracy and efficiency. Accurate and efficient injection/flowback testing is very important, given the impermeable nature of these formations and the need to complete each test as quickly as possible. Each flowback cycle yields a distinct and repeatable fracture closure signature, simplifying the interpretation of the fracture closure pressure. The objective of this paper is to share our field experience and to present a numerical analysis of the flowback test pressure responses, fracture closure behaviors, and fracture closure diagnostic methods. Examples from open-hole and cased-hole minifrac tests are used to demonstrate site operation procedures. Then, two numerical models are presented for simulating the fracture closure behavior during a flowback test. Field evidence is provided to demonstrate that the fracture closure pressures from the flowback tests are identical to those from tests without flowback. The fracture closure diagnostic methods for flowback tests are discussed, and it is found that the G-function diagnostic method yields a distinct fracture closure signal during the flowback tests. This study is intended to provide additional insights regarding flowback tests by sharing our successes, experience, and knowledge, thereby benefiting the industry.

A model of spontaneous flow driven by capillary pressure in nanoporous media

The spontaneous capillary imbibition phenomenon is a fundamental mechanism in porous media with applications in many fields. In low permeability shale reservoirs, this flow driven by capillary pressure is extremely important due to the predominance of nano-scale pores, which enhance capillary pressure and weaken hydrodynamic viscous force. This paper presents the results of an analytical model for capillary rise in nano-channels by taking into consideration the effect of inherent surface roughness. Model predictions match better with available experiments results. Relevant experiments were carried out on silicon-based nano-channels with rectangular section, which height is between 5 and 50 nm using de-ionized water. Results proved that the capillary rise kinetics in nano-channels follows the modified Lucas-Washburn law. The surface roughness adds extra resistance during the process of capillary rise, which is calculated as an equivalent porous medium layer. The capillary model is extended to porous media using the capillary bundle concept. In this model, imbibition height versus time was defined. Using this equation, the weight of imbibed liquid by spontaneous imbibition can be obtained. The results from this study demonstrate that the spontaneous imbibition in nanoporous media could be scaled and predicted. Cited as : Shen, A., Liu, Y., Farouq Ali, S.M. A model of spontaneous flow driven by capillary pressure in nanoporous media. Capillarity, 2020, 3(1): 1-7, doi:10.26804/capi.2020.01.01

Using pressure pulse decay experiments and a novel multi-physics shale transport model to study the role of Klinkenberg effect and effective stress on the apparent permeability of shales

The confining pressure imposed on a shale formation has a significant impact on the apparent permeability of the rock. Gas flow in low-permeability shales differs significantly from liquid flow because of the Klinkenberg effect, which results from gas molecule slip at the wall surfaces inside the nanopores. This effect causes the increase of apparent permeability (i.e., the measured permeability). In this study, cores extracted from four U.S. shale formations were tested using a pulse decay permeameter (PDP) under varying combinations of confining and pore pressures. The Klinkenberg coefficient was calculated to interpret the change in the measured apparent permeability as a function of pore pressure and effective stress. Next, based on the various combinations of confining and pore pressures, the actual values of the Biot coefficient were calculated by data fitting. Moreover, the samples were cored in the directions parallel to and perpendicular to the shale bedding planes to unravel the role of bedding plane direction on the apparent permeability. Furthermore, a novel, multi-physics shale transport (MPST) model was developed to account for the coupled multi-physics processes of geomechanics, fluid dynamics, and Klinkenberg effect for gas transport in shales. In the MPST model, pore pressure and effective stress are the two independent input variables, and the measured apparent permeability is the model output. The MPST model was then used to fit the PDP experimental data, and the successful data fitting confirmed that the MPST model captures the critical multi-physics processes that regulate the apparent permeability.

The Influence of an Interlayer on Dual Hydraulic Fractures Propagation

Multi-cluster hydraulic fracturing of long-range horizontal wells is an approach for enhancing the productivity of low-permeability shale reservoirs. In this study, RFPA-Petrol (rock failure process analysis on petroleum problems) is applied for modeling hydraulic fracture propagation in multilayered formations. RFPA-Petrol based on coupled hydraulic-mechanical-damage (HMD) modeling was first tested by modeling a laboratory scale experiment on a physical (cement) model with a single completion. The modeling demonstrated the capability of RFPA-Petrol for simulating hydraulic fracture propagation. Then, we used RFPA-Petrol to investigate how the difference in material properties between oil-bearing layers and interlayers and the fracturing fluid properties influence the propagation of dual fractures in multilayered laboratory-scale models. In this case, the models with geological discontinuities in the vertical direction are strongly heterogeneous and RFPA-Petrol simulations successfully modeled the fracture configurations.

Organic geochemistry at varying scales: from kilometres to ångstroms

Abstract Petroleum geochemistry has historically relied on the analysis of field samples – source rocks, oils and gases. Data collected for individual samples are considered characteristic of a specific geographical location and geological position that, when aggregated with data from other samples, can be extrapolated to larger scales. These scale-ups may be as small as a few metres, such as a detailed characterization of source rocks penetrated by a single well, to global, such as petroleum systems that now span continents due to plate tectonics. However, a single sample contains a wealth of information at smaller scales. In situ analytical techniques have improved significantly over the last decade, allowing us to examine sedimentary rocks at ever higher spatial (areal and temporal) resolution. Mass spectrometric imaging is an emerging, enabling technology that can be performed at c. 200 µm (matrix-assisted laser desorption) to 50 nm (nanoSIMS) resolution. X-ray microcomputed tomography (µ-CT) is being applied to examine the storage and transport of petroleum in low-permeability shales and carbonates at spatial resolutions as low as c. 8 µm. Pore architecture in shale, both organic and inorganic, can be modelled from small-angle neutron scattering (SANS) data and imaged directly with helium ion microscopy at c. 1 nm resolution. Atomic force microscopy (AFM) can now resolve the molecular structure of individual asphaltene molecules. Information obtained with these techniques is now revealing the fundamental nature of geological organic materials, opening the span of petroleum geochemistry from atoms to continents.

Formation conditions of organic porosity in low-permeability shale strata

Formation conditions of organic porosity in low-permeability shale strata

Geochemical attributes for source rock and palaeoclimatic reconstruction of the Auranga Basin, India

The present study aims to investigate the source and palaeoenvironmental conditions prevailed during the deposition of the Lower Permian shales of the Auranga Basin located at western flank of the Damodar valley, India. Both organic and inorganic geochemistry have been applied as tools to accomplish the objectives of this investigation. The n-alkane distribution within the samples reveals the dominance of the intermediate chain length n-alkanes over the short chain as well as long chain length homologues, possibly implying the organic matter derivation from the ferns, sphagnum moss, gymnosperms and/or aquatic plants. The intermediate chain n-alkane concentration along with its relations with the preference indices of odd to even carbons and proxy ratio as well as with average chain length may suggest the submergent aquatic plant communities as principle contributors of organic materials to the peatland. The presence of short chain length alkanes with pentacyclic triterpenoids may indicate the microbial organic matter input. The complete absence of <n-C16 alkanes and baseline humps in the pentacyclic triterpenoid chromatograms may indicate the influence of biodegradation of the organic matter in the shale samples. The pristane to phytane ratio (0.08–4.66) and the relation between pristane/n-C17 and phytane/n-C18 may imply transitional redox condition within the mire. The pristane/n-C17 ratio (0.08–1.24) may indicate the alternations of open water and swampy environments. The chemical weathering indices calculated from major elemental oxides may infer moderate to strong weathering due to reasonable period of precipitation during a wet spell. The selective trace element ratios and the palaeoclimatic factor (0.60–1.73) may, additionally, suggest high atmospheric humidity and consequent heavy precipitations that flourished the aquatic plants, which would have dominantly supplied the organic detritus in the peatland. In complementary, the hopanoid ratios, especially, the 22S/(22S + 22R) homohopane ratio may mark that the organic matter within the Auranga shales is in immature to early maturity phase for oil generation. Moreover, the combined mean random vitrinite reflectance and the thermal maturity parameter obtained from the Rock Eval data may indicate oil potential of these shales.

Experimental investigation of assessment of the contribution of heterogeneous semi-confining shale layers on mixing and trapping of dissolved CO2 in deep geologic formations

In most conceptual models of dissolution trapping of CO2, it is assumed that mixing of dissolved supercritical CO2 and formation brine occurs through density-driven convection. In our previous modeling study, we showed that the presence of continuous low-permeability shale layers in the formations causes convective shutdown through disruption of fingers, which impacts the effectiveness of mixing and trapping processes. However, these layers are naturally heterogeneous due to variations in compositional and textural properties. In the present study, we investigate the potential effects of heterogeneity present within semi-confining low-permeability layers on the overall mixing and trapping of dissolved CO2. Since accurate field experimentation in deep geologic formations is difficult due to inability to adequately characterize geology and define boundary conditions of the formation, we designed well-controlled experiments using NaBr solution and water under laboratory conditions. We conducted intermediate-scale 3D laboratory experiments under two homogeneous and one heterogeneous multilayered sand packing configurations. The results of these experiments show that connectivity of relatively higher permeability material within the semi-confining low-permeability layers contributes to mixing through (1) brine leakage between upper and lower aquifers (reverse convection), and (2) trapping through diffusion and back diffusion of initially trapped mass due to reversed concentration gradients in the long term. These findings suggest that when estimating the effectiveness of dissolution trapping in CO2 sequestration one needs to consider possible deviations from the traditional convective mixing theory in homogeneous media. Under some conditions of natural formation heterogeneity, diffusion can contribute to trapping; in some others, it may not.

Petrophysical rock typing in unconventional shale plays: The Niobrara Formation case study

Production from organic-rich shale petroleum systems is extremely challenging due to the complex rock and flow characteristics. An accurate characterization of shale reservoir rock properties would positively impact hydrocarbon exploration and production planning. We integrate large-scale geologic components with small-scale petrophysical rock properties to categorize distinct rock types in low-porosity and low-permeability shales. We then use this workflow to distinguish three rock types in the reservoir interval of the Niobrara Shale in the Denver Basin of the United States: the Upper Chalks (A, B, and C Chalk), the Marls (A, B, and C Marl), and the Lower Chalks (D Chalk and Fort Hays Limestone). In our study area, we find that the Upper Chalk has better reservoir-rock quality, moderate source-rock potential, stiffer rocks, and a higher fraction of compliant micro- and nanopores. On the other hand, the Marls have moderate reservoir-rock quality and a higher source-rock potential. The Upper Chalks and the Marls should have major economic potential. The Lower Chalk has higher porosity and a higher fraction of micro- and nanopores; however, it exhibits poor source-rock potential. The measured core data indicate large mineralogy, organic richness, and porosity heterogeneities throughout the Niobrara interval at all scales.

ROCK PHYSICS TEMPLATE TO ESTIMATE THE EFFECTS OF TOTAL ORGANIC CARBON (TOC) AND MINERALOGY ON THE SEISMIC ELASTIC PROPERTIES OF IMMATURE SHALE RESERVOIR

The low porosity and permeability shale are nowadays known as self-resourcing reservoirs. In the unique organic shales, TOC has a signifi cant contribution to the elastic properties of rocks. TOC behaves like porosity to a density log and effects in decreasing density. To reduce the uncertainty due to TOC and mineral variability effect, a quantitative interpretation of shale reservoirs should be done properly to obtain the best image of shale systems. In this study, we built rock-physics templates (RPT) to esti mate seismic response by defi ning the relationship between total organic carbon (TOC) and effective elastic properties of shale reservoirs of a data set from South Sumatera Basin, Indonesia. RPT is carried out by incorporating the amount of organic matter into shale pore space as a solid-fi lling inclusion. Moreover, shale porosity is assumed to be fully water-saturated determined by the in-situ conditions. We have estimated the general distribution of pore geometry by investigating aspect ratio from the dataset. A solid background of shale from several different minerals is estimated by using effective medium theory. Properties of porous rocks for solid pore infi ll are estimated from a generalization of Brown-Korringa Equation. Effective elastic properties of bulk rock frame fi lled with a fl uid are obtained from Gassmann equations. Results show that increasing the TOC volumes generally reduces both P-wave and S-wave velocities, acoustic impedance, and density. On the contrary, the vp/vs ratio increased as the impact of immature organic matter which will be more affecting shale rigidity than its compressibility.

A novel laboratory method for reliable water content determination of shale reservoir rocks

The paper presents a novel laboratory evaporation method (EM) of the water saturation measurement of the shale reservoir rock samples with initial water content down to below 1 wt%. The EM offers fast, efficient, and accurate measurements of the total water content, free and loosely clay-bound water. The method is characterized in terms of its operating domain and relative measurement error. The research results show that a good quality data set requires the use of fresh samples with a maximum preserved initial water saturation, fragmented into pieces with specific dimensions of a few centimetres. A comprehensive comparison between the EM and the Dean-Stark method conducted on low-permeable shale rocks of the Bazhenov formation clearly shows EM's advantages regarding accuracy and turn-around time.

SEDIMENTOLOGY, GEOCHEMISTRY AND RESERVOIR POTENTIAL OF SANDSTONES IN THE SILURIAN AKKAS FORMATION, WESTERN IRAQ

The source rock potential of “hot shales” in the Silurian Akkas Formation in Iraq has been investigated by numerous studies, but the reservoir potential of sandstone intervals in the formation has received less attention. This study investigates the sedimentology and geochemistry of sandstones from the Akkas Formation in the Akkas‐1, Akkas‐3 and KH5/6 wells in western Iraq. The composition of sandstone samples from the Akkas wells is similar; in general they are classified as sub‐litharenites, quartz‐arenites and sub‐arkoses. Scanning electron microscopic analysis identified extensive microporosity and good pore connectivity, suggesting that these sandstones have the potential to form hydrocarbon reservoirs. The sandstones from the KH5/6 well are more lithic‐rich than those from the Akkas wells and are classified as sub‐litharenites. They have larger, more connected pores and better reservoir potential. Low permeability shale intervals within the Akkas Formation and the conformably‐underlying Ordovician Khabour Formation form barriers to hydrocarbon migration into the Akkas and Khabour sandstones. Hydrocarbon migration from the Akkas “hot shales” in the Akkas field is therefore controlled by faulting and fracturing.Petrographic and whole rock geochemical analyses showed that the composition of sandstones in the Akkas Formation is different from that of sandstones in the Khabour Formation. The chemical alteration index ranges from 77.39 to 87.06%, indicating intense weathering of the provenance area before sandstone deposition. The studied samples are texturally mature which indicates good potential for fluid storage capacity. A decrease in feldspar content in the Akkas Formation is attributed to possible recycling of sediments from the Khabour Formation into the Akkas Formation following the Hirnantian glaciation, or to longer distance transportation from the source area.

Hydraulic fracturing modeling using a discrete fracture network in the Barnett Shale

Hydraulic fracturing has been a successful stimulation method for enhancing recovery in very low permeability shale gas reservoirs. Proper modeling of multistage hydraulic fracturing in shale reservoirs requires an accurate representation of the pre-existing natural fractures in the shale. The objective of this study is to utilize a 3D discrete fracture network model to simulate hydraulic fracturing in five horizontal wells A-E in the Barnett Shale. Each horizontal well had 10 stages of hydraulic fracturing stimulation. Only the well C has comprehensive logging data including an FMI (Formation Microresistivity Imager) log of the well. We characterize stochastic realizations pre-existing natural fracture network in the reservoir integrating different types of data from limited wellbore data to the geologic setting. Two fracture sets clustered using Fisher distribution after correcting for the observation biases. Fractures size constrained by induced microseismicity magnitude happened during hydraulic fracturing while fracture intensity correlated to clay contents (Gamma Ray) and distance from the fault crossing the well C. We have modeled the hydraulic fracturing in the five wells and predict that how pre-existing fractures induced to slip and contribute to permeability enhancement of the reservoir.

Can Induced Seismicity Cause Fault Leakage and How Does it Evolve with Time?

Understanding fault reactivation as a result of subsurface fluid injection is critical in geologic CO2 sequestration because it may result in enhanced fault permeability, potentially allowing CO2 leakage from the injection zone through the overlying caprock layer, often a low-permeability shale. Here we report on in situ experiments to investigate changes in permeability associated with a series of fault movements induced by repeated periods of water injection (and related fluid pressure buildup) in a borehole interval straddling a fault zone intersecting a claystone formation at 300 m depth in the Mont Terri Underground Research Laboratory (Switzerland). Three 30-minute long injection cycles were conducted, each separated by 30-minute long waiting periods without injection. Continuous monitoring of pressure, flowrate, fault displacement and micro-seismicity conducted over the entire period shows that the hydro-mechanical behavior of the fault changed from one pressure cycle to the other, with varying fluid pressures triggering micro-ruptures and leakage during the first two cycles until a magnitude -2.3 seismic event occurred during the third cycle. Using fully coupled numerical modeling, we find that the fluid pressure increase first causes repeated aseismic microruptures leading to the growth of complex flow channels within the fault zone allowing fluids to diffuse. Seismic rupture may occur when a critical pressurized patch dimension is reached. Our experimental results suggest that these below-meter scale pressurized fluid channels remain confined within the rupture patch, maintaining a slow leakage-induced creep during the inter-activation periods. These results suggest that fault zones in shale may not immediately close during the non-activation periods, but could progressively drive the fault to more instability and leakage. These preliminary conclusions remain to be confirmed over longer time periods where sealing processes could mitigate these short-term observations.

Novel Forward Model Quantifies Uncertainty of Fracture Networks

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191395, “Uncertainty Quantification of the Fracture Network With a Novel Fractured-Reservoir Forward Model,” by Zhi Chai, SPE, Hewei Tang, SPE, Youwei He, and John Killough, SPE, Texas A&amp;M University, and Yuhe Wang, Texas A&amp;M University at Qatar, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. A major portion of the uncertainty found in shale reservoirs is the result of the distribution and properties of the fracture network. However, explicit fracture models are rarely used in uncertainty quantification because of their high computational cost. This paper presents a work flow to match the history of reservoirs featuring complex fracture networks with a novel forward model. The efficiency of the model allows fractures to be characterized explicitly, and the corresponding uncertainty about the distribution and properties of fractures can be evaluated. Introduction For low-permeability unconventional shale reservoirs, the fracture network greatly determines the performance of the wells. Because of the large uncertainty of the fracture distribution, especially for natural fractures, the production behavior might differ dramatically. A possible way to characterize fractures is by use of core data, well-logging data, or seismic data. However, these data are either sparse in nature, and thus cannot be used to determine the exact location of fractures, or low in accuracy because of limited quality. An alternative approach is to use production data and characterize the fractures through history matching. Various approaches have been proposed for automatic history matching. Most of these were evaluated with conventional reservoir models through upscaling (partially the result of the cost of generating explicit fracture models and performing simulations). For fractured reservoir models, especially when explicit fracture models are used, nonlinearity is even more significant and challenges the applicability of the existing methods. In this work, the authors use the improved compartmental embedded discrete fracture model (cEDFM), combining the level-set approach and the ensemble Kalman filter (EnKF) for history matching. The cEDFM has a much better accuracy compared with the original embedded discrete fracture model (EDFM) in handling flux across the direction of fractures, which is a common case for interwell flow. The Forward Model EDFM. The concept of EDFM was first proposed in a work in which the transmissibility between fracture and the matrix is calculated in a manner similar to that used to calculate the well index. By assuming a linear relationship between the pressure in the matrix and the distance to the fracture, an analytical expression of the transmissibility can be obtained. Because the matrix grid does not need to conform to the geometry of the fractures, and the fracture is discretized by the boundary of the matrix gridblocks, this approach is flexible and compatible with traditional orthogonal or cornerpoint grid systems. In original EDFM implementation, three types of non-neighbor connections (NNCs) are considered: Between the fracture and the matrix grid it intersects Between two intersecting fracture grids Between two neighboring fracture grids from the same fracture

Geochemical factors controlling the phase behavior of Eagle Ford Shale petroleum fluids

Petroleum types in the Eagle Ford resource play span the range from black oil to dry gas and are produced along regional trends that are largely maturity controlled. A total of 61 shale samples covering all maturity zones were evaluated to document organic richness, organic matter type, and maturation characteristics using established geochemical parameters. Pyrolysis experiments were then performed to simulate the generation of petroleum fluids. Termed the “PhaseSnapShot” approach, one or more target wells with known fluid properties were used as reference; a match with that composition was made using next-formed fluids generated from the shale in a closely located well of slightly lower thermal maturity than the target well(s). Phase behavior predictions from the model were calibrated using a regional pressure–volume–temperature (PVT) database compiled from the public domain. The conceptual model that best matched the PVT data were comprised of two reactive components: (1) a mixture of kerogen and bitumen that generated petroleum within the low permeability shale matrix and (2) bitumen in zones of enhanced porosity within the matrix. The combined generation of gas from both of these components as well as the strong retention of C7+ fluids in the matrix during production were required to match the calibration data. Retention of oil was needed over a broad thermal maturity range (Rock-Eval Tmax release: 440°C –475°C). A key result of this forward model is that phase behavior and bulk compositional properties of hydrocarbons can be quickly and effectively predicted using mature shale samples as long as calibration data from PVT reports are available.

Incorporation of multi-phase solubility and molecular diffusion in a geochemical evaluation of the CO2 huff-n-puff process in liquid-rich shale reservoirs

Despite the development of horizontal well and hydraulic fracturing technologies, natural depletion is limited in low productivity, and thereby considerable hydrocarbon remains in low permeable shale reservoirs. Recent researches proved that the deployment of CO2 huff-puff process could extract the remained hydrocarbon. They quantified various mechanisms behind the process and proposed the potential for CO2 sequestration in the shale formation. However, thorough understanding of fluid transport in the CO2 huff-n-puff process has not been completed due to complexity in tight shale formations. They had a lack to analyze potential factors affecting fluid flow in the system of oil/CO2/brine/shale formation: 1) aqueous solubility; 2) molecular diffusion in aqueous and oleic phases; and 3) geochemistry. Therefore, this study diagnoses the potential factors affecting fluid flow during CO2 huff-n-puff process in the shale oil reservoirs. Then, their effects are quantified by analyzing shale oil recovery and CO2 storage capacity.Since a fraction of injected CO2 dissolves in water and oil during the CO2 huff-n-puff process, transportability is acquired by molecular diffusion in aqueous and oleic phases. In addition, dissolution of CO2 changes the pH of in-situ brine, which is a sensitive factor in geochemistry, and thereby would change physical properties of formation. Implementing these mechanisms, this study simulates the CO2 huff-n-puff process in shale oil reservoirs. It is observed that effects of aqueous solubility and geochemistry decrease oil production by 3.2% and 6%, respectively. Approximately, up to 9.5% of CO2 to be injected is sequestrated in depleted shale formation via solubility mechanism. Molecular diffusion in oleic phase increases the oil production by 2%, but that in aqueous phase is negligible. For the accurate estimation of oil production and CO2 storage capacity in the simulation of CO2 huff-n-puff process for shale oil reservoir, the comprehensive model should consider potential factors such as aqueous solubility, molecular diffusion, and geochemical reactions. Because the potential factors have been neglected in the works of other types of shale reservoirs, the proposed approaches expect to expand our understanding in the CO2 injection to tight and shale gas/oil reservoirs.