Low Water Saturation Research Articles

Reservoir characteristics of the middle Eocene Avanah Formation in Erbil governorate, northern Iraq: Integration of outcrop and subsurface data

The current work investigate the petrophysical characteristics of the Middle Eocene Avanah Formation in the Erbil Governorate using IP software to analyze the well data, integrated with the 
 petrographic investigation of the formation in the nearest outcrop in the Gomaspan section. Well logging data revealed that the main lithology of the formation is limestone and dolostone while the lithology in the Gomaspan section is composed of limestone, dolomitic limestone, marly dolomitic limestone, and thin beds of shale. The lower dolomitic unit in the subsurface section of the formation is believed to be the most suitable reservoir unit due to good petrophysical characteristics including, low water saturation, high porous medium, and the presence of movable hydrocarbon. To measure porosities, a variety of well logging techniques were used in this study. The investigated formation was divided into Avanah dense (limestone unit) and Avanah porous (dolostone unit) based on their porous components. The petrographic study shows that most pore types of the formation are secondary and represented mainly by vuggy, moldic, intercrystalline, and fracture types. Most of the fractures in the upper limestone units are filled by calcite cement. The study claimed that the lower part of the formation (dolostone unit) in both sections is considered a good reservoir.

Effect of coupled physical and chemical heterogeneity on the transport of pristine and aged pyrogenic carbon colloids in unsaturated porous media

Due to extensive application and recurrent wildfires, an increasing number of pyrogenic carbon (PyC) colloids are present in the environment, experiencing processes of environmental aging. Subsurface environments are typically heterogeneous in unsaturated conditions, which may affect the transport of PyC colloids. This study focused on the transport of both pristine and aged PyC colloids in physically (clean coarse and fine sand) and physicochemically (iron oxides-coated coarse and clean fine sand) heterogeneous porous media at three different water saturations (100 %, 70 %, and 40 %). In physically heterogeneous porous media, the decrease in water saturation from 100 % to 40 % led to a shift in the main water flow from the clean coarse sand to the clean fine sand domain, resulting in a continuous decrease in the transport of PyC colloids. In physicochemically heterogeneous porous media, the primary water flow shifted from the iron oxides-coated coarse sand to the clean fine sand domain, resulting in an initial increase and subsequent decrease in PyC colloid transport. Aging enhanced the transport of PyC colloids, attributed to the increasingly negative and hydrophilic surface. Retention profiles revealed substantial PyC colloid retention at the interface between coarse and fine sand domains. The release of retained PyC colloids exhibited two peaks at 100 % and 70 % water saturations, along with a single peak at 40 % water saturation. Additionally, the increased irreversible retention was observed at lower water saturation. This study underscores the significance of water content, environmental aging, and heterogeneity in PyC colloid transport. It provides essential insights into the environmental fate of PyC colloids in natural field conditions.

Research of hydrodynamic processes in in-situ leaching of uranium

Hydrodynamic processes in the selective transfer of uranium underground to solution were theoretically considered. The effect of the initial filtration gradient on the flow process of underground water flow of weakly permeable and poorly saturated uranium ores by the method of selective transfer of uranium to solution was studied. The hydrodynamic parameters of subsurface selective dissolution of uranium ores with low water saturation were analyzed. The consumption equations and drawings of the injection and production wells by the method of selective transfer of uranium to the solution were developed. Using the consumption equations of the injection and production wells, a calculation program was created in the C++ programming language and the analysis of the obtained results was studied.

PETROPHYSICAL CHARACTERIZATION BY 3D MODEL OF ZONES 4 AND 3 OF THE TURONIAN RESERVOIR OF THE KINKASI FIELD IN THE D.R. CONGO COASTAL BASIN

Kinkasi is one of the oil fields of the DR Congo Coastal Basin. It is essentially formed of two main geological units (A and B) in the Turonian, each composed of a succession of different horizons (Zones) according to the type of siltstone. These two main units contain 6 Zones. Unit A consists of Z6 and Z5 of Coniacian age, while the rest of the reservoir (Z4, Z3, Z2 and Z1) is of Turonian age which is characteristic of Unit B. Indeed, the present study is devoted to the petrophysical characterization of the two zones Z4 and Z3 of the unit B in order to locate the interesting zones to develop this oil field. For this fire, we used the data of 11 wells having the geographical coordinates, the porosity, the permeability as well as the water saturation. The processing and interpretation of these data using the Kriging method allowed us to deduce from the scale of appreciation the areas that contain high values of porosity, permeability and water saturation. Porosity in zones 4 and 3 varies from good to very good, saturation 3 to 59% for zone 4 and 32 to 53% for zone 3 as well as permeability from poor to low for both zones. The combined interpretation of these three properties allowed us to find an interesting zone located towards the east of zones 4 and 3 with high porosity and permeability values and low water saturation values.

Effective Relative Permeabilities Based on Momentum Equations with Brinkman Terms and Viscous Coupling

Summary The relative permeability expresses the mobility reduction factor when a fluid flows through a porous medium in the presence of another fluid and appears in Darcy’s law for multiphase flow. In this work, we replace Darcy’s law with more general momentum equations accounting for fluid-rock interaction (flow resistance), fluid-fluid interaction (drag), and Brinkman terms responding to gradients in fluid interstitial velocities. By coupling the momentum equations with phase transport equations, we study two important flow processes—forced imbibition (coreflooding) and countercurrent spontaneous imbibition. In the former, a constant water injection rate is applied and capillary forces are neglected, while in the latter, capillary forces drive the process and the total flux is zero. Our aim is to understand what relative permeabilities result from these systems and flow configurations. From previous work, when using momentum equations without Brinkman terms, unique saturation-dependent relative permeabilities are obtained for the two flow modes that depend on the flow mode. Now, with Brinkman terms included, the relative permeabilities depend on local spatial derivatives of interstitial velocity and pressure. Local relative permeabilities are calculated for both phases utilizing the ratio of phase Darcy velocity and phase pressure gradient. In addition, we use the Johnson-Bossler-Naumann (JBN) method for forced imbibition (with data simulated under the assumption of negligible capillary end effects) to calculate interpreted relative permeabilities from pressure drop and average saturation. Both flow setups are parameterized with literature data, and sensitivity analysis is performed. During coreflooding, Brinkman terms give a flatter saturation profile and higher front saturation. The saturation profile shape changes with time. Local water relative permeabilities are reduced, while they are slightly raised for oil. The saturation range where relative permeabilities can be evaluated locally is raised and made narrower with increased Brinkman terms. JBN relative permeabilities deviate from the local values: The trends in curves and saturation range are the same but more pronounced as they incorporate average measurements, including the strong impact at the inlet. Brinkman effects vanish after sufficient distance traveled, resulting in the unique saturation functions as a limit. Unsteady state (USS) relative permeabilities (based on transient data from single-phase injection) differ from steady-state (SS) relative permeabilities (based on SS data from coinjection of two fluids) because the Brinkman terms are zero at SS. During spontaneous imbibition, the higher effect from the Brinkman terms caused oil relative permeabilities to decrease at low water saturations and slightly increase at high saturations, while water relative permeability was only slightly reduced. The net effect was a delay in the imbibition profile. Local relative permeabilities approached the unique saturation functions without Brinkman terms deeper in the system because phase velocities (involved in the Brinkman terms) decreased with distance. In both systems, scaling and simulations demonstrate that the relative change in relative permeabilities due to Brinkman terms increases with the Brinkman coefficient, permeability, and inverse squared distance from the inlet.

Petrophysical Properties and Identification of Electrofacies from Well Log Data of Nahr Umr Formation in Subba Oilfield, Southern Iraq

The main purpose of this study is to identify electrofacies and evaluate the petrophysical properties of the Nahr Umr Formation in four wells: A, B, C, and D in the Subba oilfield, southern Iraq. The petrophysical properties, such as shale volume, porosity, water saturation, hydrocarbon saturation, and bulk water volume, were computed and interpreted using Techlog software. According to the interpretation of density, neutron, and gamma ray sonic logs and deep resistivity logs using the IPSOM technique, four electrofacies were identified as sandstone, shaly sand, sandy shale, and shale electrofacies. The formation was divided into three parts based on well log interpretation and petrophysical analysis: the upper part, middle part, and lower part Interpretation of formation lithology and petrophysical parameters shows that the lower part consists mainly sandy shale with layers of sandstone and shale high porosity and high oil saturation whereas middle part consists mainly of sandstone, alternating with thin bedded of sandy shale and shale with high porosity and medium oil saturation. The upper part consists mainly of a sandy shale alternating with shale and shaly sand with high porosity, hydrocarbon saturation, and lower water saturation.

Hydrocarbon potential and reservoir characteristics of incised-valley transgressive sandstones: A case study of the Messinian gas reservoirs (Nile Delta Basin, Egypt)

The incised-valley sandstones have been identified as a significant contributor to global hydrocarbon resources. This study aims to assess the Messinian Abu Madi (AM) sandstone's reservoir properties in the incised valleys of the Baltim, Nidoco, and Abu Madi gas fields in the Nile Delta Basin, Egypt. The hydrocarbon potential of these sandstones is assessed through the analysis of seismic, well logs, and core data. The seismic interpretation reveals that extensional faults played a significant role in controlling the deposition of the Abu Madi Formation in the study area, formed during the tectonic rifting of the Messinian age. The northernmost portion of the study area in the Abu Madi field exhibits the most promising location for gas exploitation, suggesting the need for further exploration and evaluation. The sandstones exhibit a fining upward trend with a relatively clean composition, moderate to well sorting and mild calcareous tendencies. The presence of sedimentary structures, such as cross-bedding and ripples, suggests a dynamic depositional environment. The rock composition, dominated by quartz with variable sorting and cementation, influences the porosity and permeability of the sandstones. Petrophysical investigations indicate favourable reservoir conditions with significant porosity and permeability, enhancing hydrocarbon storage and extraction potential. The analysis of petrophysical parameters in the AM sandstones reveals favourable properties for gas production, including low shale content (4%–12%), high porosity (18%–22%), and low water saturation (20%–54%) levels. The findings of this study indicate that the gas-pay zones within the Abu Madi sandstones are primarily associated with the transgressive sandstones of the estuarine facies (TST) rather than the lower sandstones of the fluvial facies (LST). The complex sandstone channels within the TST exhibit diverse geometries and contribute to reservoir heterogeneity. The presence of well-connected channels enhances reservoir productivity by facilitating fluid flow. The understanding of the distribution and characteristics of these channels is essential for reservoir characterisation and optimisation of hydrocarbon recovery.

Cementation Exponent Estimates and their Impact on Oil Initially in Place Calculations : A Case Study from Lower Qamchuqa Formation in the Bai Hassan Oilfield, Northern Iraq

The effect of Cementation Exponent has been investigated on the calculated water and hydrocarbon saturations and the estimated oil initially in place. The Aptian Lower Qamchuqa (Shua'iba) Formation from the well BH-96, Bai Hassan Oilfield, is used as a case study. Four different values of Cementation Exponent were applied in calculating water saturation using the Archie equation. The static value of 2 commonly used for carbonate reservoirs was one of the cases used to calculate an average of 68% water saturation. In the second case, the value of 1.81 is used for m based on the average m values obtained through testing 22 core samples in the laboratory. The average of 60.5% Sw was calculated for the studied part of the Lower Qamchuqa Formation in this case. The Pickett plot method was used as a third case, and 1.65 was estimated as the m value through which the average of 54% Sw was calculated. In the fourth case, variable values of m were used for the different depth intervals from which core samples were tested in the laboratory. In this case, the calculated average water saturation was equal to 60%. The upper part of the studied section was generally of low porosity and high water saturation, whereas the middle and the lower parts contained hydrocarbons with different saturations. Using shale content, porosity, permeability, and water saturation cutoffs for the four different cases, the net to gross pay ratios were calculated. The ratios ranged between 56.5% in the case of using the 1.65 value of m and 47.6% in the case of using variable core tested m values, and accordingly, the difference of about 4 m in net thickness is expected to be underestimated or overestimated, respectively, when is calculated.

Exploring Reservoir Potential of the "X Field" Offshore, Niger Delta Basin: An Emphasis on Lithofacies, Depositional Environments, and Petrophysical Characteristics

The geological circumstances under which sediments are built throughout time are referred to as depositional environments. The features of the sediment, such as its texture, composition, and permeability, are influenced by these depositional environments, and these qualities ultimately define the reservoir quality. This study focuses on identifying reservoirs in the western offshore region of Nigeria's Niger Delta Basin and evaluating their properties, such as lithofacies, distribution, and petrophysical characteristics like porosity and permeability, using well log analysis. By utilizing relevant and easily accessible well log data, the depositional environment and quality of the reservoir were evaluated. The data analysis involved examining gamma-ray log patterns, spontaneous potential, deep resistivity, neutron, and density. The thickness of the reservoirs varies between 15 and 440 meters, with thicker reservoirs likely being composite structures formed from layered channels. Sands deposited in high-energy settings have higher levels of porosity and permeability. Sands C and D are the most porous and permeable sand units in the field, while the remaining sands have medium permeability. Hydrocarbons are present in sands B, C, D, and E in varying fluid types and column diameters. The reservoir sands C, D, and E have high hydrocarbon saturation and low water saturation, indicating that more oil than water will be produced. On the other hand, irreducible sand B suggests that more water than oil will be produced. Reservoir sands B, C, and D contain only water and oil. This information can aid in locating production platforms and optimizing hydrocarbon recovery, as well as improving reservoir performance estimates. The geological and petrophysical data collected in this study can also guide the analysis of other fields similar to the "X Field" in Nigeria's Niger Delta offshore region.

Effects of Pore Water on the Heterogeneity in Nanopore Structures of Deep Marine Shales: A Multifractal Study on As-Received Shale Samples from the Southern Sichuan Basin, China

Shale strata generally contain a certain amount of pore water that accompanies the whole diagenetic and thermal evolution processes of shales. The distribution and occurrence characteristics of pore water significantly influence the nanopore structures of shales, which subsequently affects the accumulation and production of shale oil and gas resources. Based on a set of fresh Wufeng–Longmaxi (WL) shale samples from the deep marine strata in the southern Sichuan Basin, this study investigated the effects of pore water on the pore heterogeneity of shales by a multifractal method. The results show that (1) the deep WL shales have low pore water content (CPW) and water saturation (SEW), with average values of 7.47 mg/g and 35.21%, respectively, and the CPW and SEW of the shales are mainly controlled by clay mineral content. (2) Under dried conditions, the pore heterogeneity of high-probability measure areas has negative relationships with the clay mineral content and pore volumes with pore widths of 4–10 nm, and the pore connectivity is mainly controlled by clay mineral content. Under as-received conditions, however, the pore heterogeneity of low-probability measure areas and pore connectivity have positive relationships with clay mineral content and pore volumes with pore widths less than 4 nm. (3) Under as-received conditions, the pore water mainly occupies the nanopore with pore widths less than 4 nm and reduces the effective pore spaces and connectivity, which reduces the pore heterogeneity of high-probability measure areas and enhances the pore heterogeneity of low-probability measure areas.

Formation evaluation and rock type classification of Asmari Formation based on petrophysical- petrographic data: A case study in one of super fields in Iran southwest

The Oligo-Miocene Asmari Formation is one of the most important hydrocarbon reservoirs in the Middle East. The oilfield under study is one of the largest oilfields in the Zagros basin with the Asmari Formation being the major reservoir rock. In this study, petrographic analyses, petrophysical data and neural network clustering techniques were used for identifying rock types in the Asmari reservoir. Facies analysis of the Asmari Formation in the study area has resulted in the definition of 1 clastic lithofacies and 14 carbonate microfacies types. Using petrophysical logs from 43 wells and their correlation with capillary pressure ( P c ) curves, led to the recognition of 7 electrofacies (EF1-EF7). Microscopic evidence of Electrofacies group C1 and S1 show that the sedimentary facies of these electrofacies are most commonly found in restricted and shoal facies belts zone. Also, petrographic studies show that the sedimentary facies of C2, C3, C4, S2 and S3 were formed in the open marine, Lagoon, and Tidal flat facies belt zone of homoclinal ramp sedimentary environment during the Oligo-Miocene based on relative sea level changes respectively. The link between electrofacies and geological data indicated that both sedimentary and diagenetic processes controlled the reservoir quality of the Asmari Formation. Porosity, permeability and water saturation were used to estimate the reservoir quality of each electrofacies. EFs 1 and 2 with high porosity and permeability, low water saturation is considered as the best reservoir with regard to sedimentary textures (dolowackestone and dolograinstone) and the effect of diagenetic processes such as dolomitization processes. Vuggy, growth framework and interparticle porosities are major in EF-2, while the intercrystalline porosity is the major type in EF-1. EFs 3 and 4 show low values of porosity, permeability and high percentage of water saturations, which characterizes them as poor reservoir rocks. Finally, EF-5 is the only electrofacies in the siliciclastic parts of the Asmari reservoir, which is composed of rounded and well-sorted quartz grains that are slightly cemented. In sandstone electrofacies, electrofacies EF- 5 (S1), is the best type of sandstone reservoir rock and to move towards electrofacies EF-7 (S3), will reduce reservoir quality. In carbonate electrofacies, also, electrofacies no 1, the best type of carbonate reservoir rock can be observed and move towards electrofacie number 4, lower quality of reservoir rocks is seen. • This research can be useful in the development of the field and determining oil production in the future of similar fields.

Reservoir characterization, in relation to the petrophysical modeling of Baharyia formation, Razzak field, northern western desert, Egypt

The present work aims to investigate the reservoir characterizations of the Lower Cenomanian Baharyia Formation by creating isoparametic maps to calculate the petrophysical parameters and detect the favorable parts for oil accumulations using the available well logging data. Baharyia Formation is one of the main hydrocarbon sandstone reservoirs in the northern Western Desert of Egypt. About 90% of the Western Desert field produces form Baharyia sandstone Formation. This has been achieved through the analyses of the conventional wireline logs and petrophysical modeling. The Baharyia Formation comprises a complex of depositional lithofacies such as interbedded siltstone, shale, sandstones and pebbly sandstones. Petrophysical modeling of the Baharyia Formation was performed, based on the interpretation of complete wireline logs from five wells in Razzak oil field, north Western desert, Egypt. Petrophysical analysis accomplished, such as: shale volume, total and effective porosities, water saturation and hydrocarbon saturation, were deduced and utilized in the petrophysical subdivision of the Baharyia Formation. Relations between theses petrophysical parameters are established to define the implications of such parameters on the Baharyia Formation. Iso-parametric and litho-saturation crossplots are used to delineate variations in petrophysical parameters across the area. The obtained petrophysical results reveal that, the Baharyia Formation have a good reservoir quality, with high effective porosity values exceeding 18%,volume of shale about 30% and low water saturation values of 25%. The rock genetic types of the Baharyia Formation deduced form the log curve shapes proved that the Baharyia Formation was deposited from fluvial to marine environments passing through the tidal flood plain conditions. However, the lithology of the Baharyia Formation composed of sandstone, siltstone, shale and minor limestone inter-beds.

Geophysical structural interpretation of Esh El Mallaha basin, southern Gulf of Suez: implications for oil potential in South Malak and Rabeh fields

Esh El Mellaha area is located at the western margin of the Gulf of Suez rift system. It is one of the most important potential hydrocarbon resources in the north Eastern Desert. Satellite images, field observations (e.g. measure relevant structures, lineaments mapping, compile maps at the outcrops) and seismic data were used to delineate the surface and subsurface structural elements of the area west of Esh El Mellaha range. The present study revealed that, the main structural trends have the directions NW–SE, NE–SW to NNW–SSE, WNW–ESE and ENE–WSW. The NW–SE trending faults are the major dominating trend which is related to the Gulf of Suez rift opening. The seismic interpretation step led to the identification of four prominent continuous reflectors and five depositional seismic sequences. The recognised seismic reflectors were named; Q, F, R and K and ranging in age from the Lower Miocene to the Middle–Upper Miocene. The petrophysical examination exhibits good reservoir quality for the sandstones of Matulla Formation in Rabeh and South Malak fields, southern Esh El Mellaha area. These reservoirs display low shale volume (5–20%); high effective porosity (10–20%), relatively low water saturation (40–55%) and pay thickness varies between 30 and 85 ft. Accordingly, this study highlights the oil potentiality of the Matulla sandstones for further exploration purposes in both Rabeh and South Malak fields.

Effect of initial water saturation on the performance of fracturing fluids with and without polyallylamine under simulated EGS conditions

Objectives/scopeStimuFrac (US Patents 9,873,828 B2 and 9,447,315 B2), a CO2-reactive polymer aqueous solution [polyallylamine (PAA) 1wt% in water] combined with CO2, can potentially be used as a less water-intensive fracturing fluid for enhanced geothermal systems (EGS). Our previous results show that in hot dry rock (HDR), PAA/CO2 fracturing fluids outperformed other fluids such as water, CO2, and CO2/water in generating large fractures with less fluid consumed. The objective of this work is to investigate the effect of initial water saturation on the performance of StimuFrac by conducting hydraulic fracturing tests with ½ foot cubic rock samples held under representative EGS stress/temperature conditions and by using cyclic injection strategies (under constant injection rate). The resulting fracture hydraulic conductivities, breakdown pressures, and volumes of fluids required are compared. Methods/procedures/processTo simulate geothermal reservoir conditions, in all tests, the rock sample was held under triaxial confinement and at 200 °C, and different volumes of water were initially injected into the rock sample before any fracturing processes were initiated. For the single-cycle PAA (or water) alternating CO2 (PAG or WAG) injection fracturing experiments, one complete cycle consisted of two steps: (1) injecting a PAA slug (or water slug) followed by (2) injecting CO2 to initiate and propagate the fracture. For experiments involving multiple injection cycles, the CO2 injection pressure is increased until it peaks and begins to decline (indicating fracture initiation at this moment), and then continued being injected for another 30 s to propagate the fracture. Then, these two-step cycles [injection of PAA (or water) followed by CO2 injection (up to 2–4 mL/min)] are repeated. Applications/significance/noveltyThe results of this study suggest that water saturation significantly affects the fracturing fluid transmission into the rock pore space, thus affecting fracture initiation and propagation. In this study, fracturing tests via a single injection cycle or multiple injection cycles were performed. When the rock samples are split in half following testing, it is evident that fracture propagation is considerably restricted under high water saturation conditions (where a three-day initial water injection was conducted) in comparison to stimulation experiments carried out in hot and dry rock. The fractures propagate less than 1/3 of the distance from the wellbore to the outer rock surface, and in some cases, no fracture is generated. This may be caused by leak-off dominating the fracturing process and the fluid injection rate is insufficient to overcome leak-off, even under high injection rate conditions. Additionally, CO2 could be leaking off into the wellbore annulus and this may be making it more difficult to generate sufficiently high-pressure gradients away from the near-wellbore region. Under low water saturation conditions (dry rock or after 1-day initial water injection), PAA/CO2 consistently generated significantly larger fractures compared with the other fluids. CO2 generated large fractures only in the hot dry rock and only when using high injection rates, though data variability is high.

Reservoir Characterization using Petrophysical Evaluation of W-Field, Onshore Niger Delta

Reservoir characterization of W-field, onshore Niger Delta was carried out using petrophysical evaluation of well logs. Three reservoir sand intervals (A, B, C) were identified and correlated across four wells (W1, W2, W3, W4) in W-field using the gamma ray, while the fluid identification of each reservoir was achieved using the resistivity log. The reservoir C interval was selected and utilized for petrophysical interpretation was penetrated at depths 11741-11945ft, 11933-12173ft, 11658-11847ft and 11926-12095ft across all wells respectively.The average values of gross thickness, volume of shale, effective porosity, total porosity, permeability, water saturation and hydrocarbon saturation of the delineated reservoir sand are 200.5ft for gross thickness, 18% for shale volume, 21% for effective porosity, 26% for total porosity, 1071.74mD for permeability, and 28% for water saturation and 77% for hydrocarbon saturation. Petrophysical evaluation revealed that porosity and permeability are very good to excellent in the field. The reservoir is classed as clean sands based on the high net to gross ratio (>70%) and the low shale volumes (<30%). Consequently, the low value of shale volume, low value water saturation, high value of hydrocarbon saturation and the good porosity and permeability properties of the reservoir of interest suggest economical and commercial quality and viability of the wells within this field.

Seismic reservoir characterization of the syn-rift lower Miocene Rudeis Formation in the July oilfield, Gulf of Suez basin, Egypt: Implication for reservoir quality assessment

The Lower Miocene Rudeis Formation is among the most potential oil-bearing sedimentary sequences in the Gulf of Suez (GOS), representing the main producer of Egyptian oil. This study concerns primarily with revealing the reservoir characteristics and facies distribution, as well as the implication of the predominant diagenetic factors on the quality of the Lower Miocene syn-rift Rudeis reservoir in the July oilfield. Therefore, this study integrates 2D seismic, and wireline logs, as well as conventional and special core analyses to determine the reservoir characteristics and facies distribution. The interpreted data elucidate four different seismic facies in the Rudeis Formation with a net pay thickness ranging from 29 to 233 m in the studied wells of 16.3% average porosity, 62.9% average oil saturation, and 9.3% average shale volume. Four seismic facies (SF1-SF4) were interpreted and correlated with the Rudeis clastic deep-water turbiditic succession. The 3D static property models revealed that the best reservoir facies in terms of low shale content and water saturation, as well as high porosity, coincide with the submarine channels and fans containing coarse-grained, clean sandstones. From the core analysis, the Lower part of the Rudeis sequence is subdivided into five reservoir rock types (RRTs). The RRT1 is characterized by the best reservoir quality; it is composed of quartz arenites, sublithic arenites, and subfeldspathic arenites. In contrast, the RRT5 represents the lowest reservoir quality; it consists of very coarse siltstone, laminated glauconitic siltstone, and highly compacted dolomitic and calcareous quartz arenites. The poor reservoir characteristics of the RRT5 are attributed to tight compaction, cementation, and early dolomitization phase, whereas the highest quality of the RRT1 is related to fracturing and dissolution processes. The RRT1 rocks are mostly associated with the submarine channel and fan facies, whereas the poor quality RRT5 sediments were accumulated as hemipelagic/background. This integrated workflow study can be applied to further case studies in the Middle East, Africa, and the other analogues all over the world.

Integrating seismic attributes and rock physics for delineating Pliocene reservoir in Disouq field, Nile Delta, Egypt

The Nile Delta is known as the most prolific gas province in North Africa. Gas exploration and production were the main targets over decades in the Nile Delta. The integration of petrophysical analysis, seismic interpretation, and seismic attributes could indicate the presence of gas in Disouq field, which is located in Nile Delta, Egypt. Well log data showed that the reservoir is classified into three zones (A, B, and C). These zones are characterized by low gamma ray (around 35%), with relatively high porosity (around 29%) and low water saturation (36–38%). Structural and stratigraphic interpretation was conducted in order to investigate the extension and geometry of the reservoir, in addition to the faults affecting the study area. The reservoir is represented by a channel of Pliocene age, characterized by the low impedance sand saturated by gas. Near and far offset data show the gas effect. There is an increase of the negative amplitude from near to far offset. The amplitude map and structural contours match well and show good conformance. Seismic attributes including surface attributes and “Red Green Blue/colour blending” help in delineating the extent and geometry of the reservoir, in addition to the possible prospect. Finally, the volume of original gas in place was estimated what showed that the study area is of great economic interest.

Numerical simulation of fracturing and imbibition in shale oil horizontal wells

The shale oil reservoir is characterized by tight lithology and ultra-low permeability, and its efficient exploitation requires the technology of multi-stage and multi-cluster hydraulic fracturing in horizontal wells and shut-in imbibition. After multi-stage and multi-cluster hydraulic fracturing, a complex fracture network is formed, and a large volume of frac fluid is stored within the fracture network. During shut-in, imbibition and exchange between oil and water occurs under the action of the capillary force and osmotic pressure, and the formation pressure builds up in the shale reservoir. On basis of the characteristics of shale oil reservoir, we establish a model of imbibition during fracturing injection and shut-in by coupling oil–water two-phase flow and saline ion diffusion in the hydraulic fractures (HFs) network, natural fractures (NFs) and matrix system under the action of capillary force and osmotic pressure. The DFN method and the multiple continuum method are introduced to characterize fluid flow between the HF and the NF and that between the NF and the matrix respectively, which avoids the problem of a large amount of computation of seepage within the complex fracture. Then, the discrete fracture network (DFN) model and the multiple continuum model are solved with the finite element method, and it is verified in flow field, saturation field and concentration field that the models are accurate and reliable. We propose the imbibition exchange volume for quantitative evaluation of the imbibition degree and a method of calculating the imbibition exchange volume. Simulation of oil and water flow in the fracturing and shut-in stages is performed based on these models. It is found that imbibition in the shale reservoir is driven by mechanisms of pressure difference, capillary force and osmotic pressure. The osmotic pressure and capillary force only cause an increase in the imbibition rate and a reduction in the imbibition equilibrium time and do not lead to variation in the peak of imbibition exchange volume. The imbibition equilibrium time under the action of the capillary force and osmotic pressure is reduced from 150 to 45 d compared with that under the action of the pressure difference. If imbibition equilibrium is reached, low initial water saturation, strong rock compressibility, high formation water salinity and high matrix permeability enhance imbibition and exchange of oil and water in the reservoir. The leakoff volume of frac fluid is generally larger than the imbibition exchanged volume. Leakoff equilibrium occurs slightly earlier than imbibition equilibrium. The imbibition equilibrium time is mainly affected by reservoir permeability and NF density. The number of interconnected fractures mainly affects the frac fluid volume within the hydraulic fracture in the fracturing process. The stimulated reservoir volume (SRV) mainly affects frac fluid imbibition exchange in the shut-in process.

Effects of Low Temperature and Water Saturation on the Blast Response of Carbon and E-Glass Epoxy Composites

Effects of Low Temperature and Water Saturation on the Blast Response of Carbon and E-Glass Epoxy Composites

Reservoir characteristics of different shale lithofacies and their effects on the gas content of Wufeng-Longmaxi Formation, southern Sichuan Basin, China

Various shale lithofacies differ significantly in terms of gas content and pore structure characteristics. In this study, FE-SEM, low-pressure gas adsorption (LPGA), in-situ reservoir water saturation restoring, and high-pressure (0–51Mpa) methane adsorption were conducted to systematically characterize pore structure and evaluate the gas content of different shale lithofacies in the Wufeng-Longmaxi Formation, southern Sichuan Basin. The mineral compositions identified four shale lithofacies, and pores are abundant in siliceous shale and mixed shale. Siliceous shale has the largest pore volume (PV) and specific surface area (SSA), averaging 0.0310 cm3/g and 25.827 m2/g, respectively. However, the PV and SSA are lowest in argillaceous shale, averaging 0.0217 cm3/g and 18.734 m2/g, respectively. Water saturation is positively correlated with clay minerals, and argillaceous shale possess the highest water saturation of 60% due to the highest clay content. The supercritical Dubinin-Astakhov (S-DA) excess adsorption model predictions deviated less from the measured data and fitted well. The shale adsorption capacity are dominated by TOC content and total SSA. However, water and temperature have an inhibitory activity on adsorption capacity, with the adsorption capacity of water-bearing shales decreasing by 28%∼81% at a water saturation of 30%∼65% compared to dry shales. As the temperature increased from 40 °C to 80 °C, the methane adsorption capacity decreased from 3.95 to 2.79 m3/t, a 29% decrease. The shale gas content prediction models were established and extrapolated into the functions of reservoir depth. Deep shale gas reservoirs are dominated by free gas, accounting for over 90% at 5000 m. Siliceous shale has the highest gas content, followed by mixed shale, argillaceous-siliceous shale, and argillaceous shale. It is estimated that siliceous shale has a three-fold higher gas content than argillaceous shale. Siliceous and mixed shale are favorable reservoirs for shale gas exploration and development due to their high gas contents and low water saturation.