Md Permeability Research Articles

In-situ hydrothermal upgrading and mechanism of heavy oil with nano-Fe2O3 in the porous media

Hydrothermal upgrading is a promising technology for heavy oil, yet the impact of reservoir conditions on the catalytic effect of catalysts and the pathway are not clear. In this study, the effect of the formation environment on the catalytic upgrading process was investigated through simulating the reservoir conditions (2000 mD permeability, 25 % porosity) for catalytic hydrothermal cracking of heavy oil. Under the hydrothermal upgrading conditions（240 ℃, 24 h, 50 wt%, 0.1 wt% nano-Fe2O3）, 9.15 % of the heavy component(5.1 % resin and 4.05 % asphaltene) was converted to light component. The content of hydrocarbons below C17 in the saturated fraction increased from 36.29 % to 59.85 %. The structure of the asphaltene was disrupted resulting in a lower level of asphaltene stacking, and NC/NH ratio increased 13.61 % compared to heavy oil. In addition, the reservoir condition with quartz as the supporting medium improved the catalytic ability of iron oxide nanoparticles. When injected into the reservoir medium, nano-size facilitated dispersion on the surface of the proppant and inhibited the aggregation of nanoparticles, which ensured the continuous operation of the active sites on the surface of the catalyst. Electron transfer of Fe2+/Fe3+ catalyzed the heterolytic cleavage of covalent bonds of H2O/heavy oil molecules was the mechanism for heavy oil upgrading. These findings demonstrated the feasibility of in-situ upgrading of heavy oil through the use of nano-catalysts under reservoir conditions.

Modeling porosity and permeability evolution of burrow fillings with packstone fabric in the Upper Jurassic Hanifa Formation, central Saudi Arabia: A digenetic backstripping study

Understanding the development and characteristics of burrow fillings (BF) is crucial for predicting porosity, permeability, and fluid flow behavior in bioturbated carbonate reservoirs. Advanced imaging, digital rock modeling, and backstripping techniques offer valuable insights into this development. In this study, we examined the BF in the bioturbated strata of the Upper Jurassic Hanifa Formation (central Saudi Arabia) to understand how sedimentological and diagenetic processes—such as compaction, dolomitization, and dissolution—influence porosity and permeability over time.Backstripping results provide significant insights into the evolution of porosity and permeability within packstone BF of the studied strata. We found that compacted, grain-supported BF exhibit limited improvement in porosity and permeability post-compaction. In contrast, less compacted intervals with open fabric BF can achieve up to 20% porosity and >5000 mD permeability in their grainstone versions. Notably, even with over 10% mud content, open fabric BF maintained substantial permeability (>1000 mD) due to a connected pore network. Moreover, these BF have the potential to recover porosity and permeability after complete pore network occlusion by the mud matrix through diagenetic processes like preferential dolomitization of the mud matrix and subsequent dissolution.The findings underscore the dynamic evolution of porosity in packstones within BF of bioturbated strata. Initially, mud-rich packstones with low porosity and permeability can transform into more permeable packstones through dolomitization and dissolution. Conversely, initially high-quality, mud-poor packstones with high porosity and permeability may degrade due to compaction. The quantification of porosity and permeability using digital rock modeling and backstripping techniques provides an objective and comprehensive understanding of these evolving properties, highlighting key phases and processes affecting reservoir quality. The approach of integrating digital rock modeling and backstripping technique enhances the ability to predict subsurface storage and flow capacity in bioturbated strata.

Diagenesis including cataclastic band development in the Permian Penrith Sandstone, Vale of Eden Basin, England

Diagenesis in the Penrith Sandstone is characterized by early hematite and mixed illite/smectite cementation, followed by burial compaction, feldspar and two episodes of quartz cementation. The primary quartz overgrowths are characterized by heterogenous luminescence; however, the secondary quartz overgrowths are characterized by thinner and darker luminescence. Cataclasis post-dates primary quartz cementation, and significantly reduces grain and pore aperture size. The apex of mercury volume for a deformed sample was reduced up to three times in comparison with the undeformed rock. Dissolution occurred during cataclasis as authigenic hematite was removed in deformation zones, improving pore aperture size and consequently enhancing sandstone porosity and permeability. Recent fracturing created fractured-pores and improved porosity and permeability in tight cataclastic samples. Evidence for syn-cataclastic dissolution is observed in the samples studied. This is indicated by the dissolution of authigenic feldspars and the enhancement of poroperm parameters adjacent to cataclastic zones and the absence of hematite cement within them. Based on those the sequence of diagenetic evolution in the Penrith Sandstone can be reconstructed. Host samples were characterized by good to very good poroperm values, varying between 20 and 24% porosity and from 809÷1445 mD permeability. Cataclastic core plugs have 13÷21% porosity and 0.12÷39 mD permeability. The porosity reduction by cataclasis was estimated to be as much as 4.5% on average. Fracturing and dissolution improved poroperm parameters in studied samples. Recently fractured core plugs have about 292 mD permeability on average. Dissolution-cataclastic samples have 32% porosity and 18 mD permeability, whereas dissolution-host samples have 31% porosity and maximum permeability as much as 2469 mD on average. Cataclasis occurred in combination with in situ significant reservoir dissolution and fracturing may improve a sandstone reservoir in excellent quality.

Evaluation of porosity and permeability of sandstones within the Oti Group of the Volta Basin using petrophysical and petrographic techniques

Evaluation of porosity and permeability of sandstones within the Oti Group of the Volta Basin using petrophysical and petrographic techniques

Characterization of Upper Cretaceous Matulla and Wata clastic reservoirs from October field, Central Gulf of Suez, Egypt

The objective of this study was to integrate petrographic thin sections, SEM, XRD, routine core analysis, gas chromatography, and wireline logs to present a comprehensive petrographic and petrophysical assessment of the shallow marine clastic reservoirs of the Coniacian-Santonian Matulla Formation and upper Turonian Wata Formation from the October field, Central Gulf of Suez Basin. The fine to very fine-grained glauconite-bearing subarkose quartz arenites of the Matulla and Wata reservoirs exhibit good intergranular primary porosity with good pore connectivity. Moderate to slight compaction and grain to grain pressure solution resulted in a slightly inhomogeneous packing of framework grains. Feldspar dissolution contributed to the secondary porosity which improved the reservoir quality, while quartz overgrowth and minor calcite cementation are inferred as porosity destroying diagenetic agents. Pore-filling kaolinite and clay phases also had a negative effect on reservoir storage capacity. Routine core analysis indicated > 20% porosity and up to 412 mD permeability in the meso-megaporous sandstones of both the reservoirs. Permeability anisotropy analysis of Matulla samples indicates the dominance of primary depositional fabric and isotropic pores with minor scattered/connected horizontal pores and vertical pore connectivity. Wireline log-based quantitative petrophysical assessments exhibit low shale volume and higher hydrocarbon saturation (up to 80%) on both the reservoirs, which is also supported by the gas chromatography data confirming the presence of oil in the Matulla, and Wata pay zones based on interpreted gas balance, wetness, and character ratios. The study concludes excellent reservoir properties in the Upper Cretaceous clastic intervals of the October field.

Experimental study on dynamic pore-fracture evolution and multiphase flow in oil-saturated coal considering the influence of in-situ stress

The methane drainage in liquid-saturated coal is directly related to the multiphase flow in complex geological structures. In this study, the pore-fracture dynamic evolution induced by in-situ stress and the corresponding gas-liquid migration and morphology characteristics were investigated by a self-developed online LF-NMR triaxial stress system. The dynamic variation, obvious change, and slight response were occurred at the migration pore (MP＞3ms), percolation pore (0.3ms < PP < 3ms), and adsorption pore (AP<0.3ms) with the increased stress, and development of gas channel was contributed by MP (15%–20%), AP (5%–10%), and PP(0–5%) responding to the gas flooding. The pore-fracture successively experienced compression, dilation, expansion, and coalescence, and PP and MP dominated the fracture initialization and connection. The permeability is negatively correlated with the fractal dimension of the pore-fracture structure and is exponentially related to the porosity and MP porosity. The longitudinal shear fracture is beneficial for the gas-liquid migration, and the horizontal tension crack connects the scattered pore and branch fracture. The gas channel was influenced by the liquid capillary pressure and gas jiamin effect in poor pore-fracture and mainly influenced by the gas slippage effect, immiscible behavior, and fracture surface tension force in mature pore-fracture. The optimal gas channel occurred at the crack-propagation period, which was located at around 70% peak strength with 1.5md permeability, high liquid relative permeability and lower gas relative permeability. The findings provide significant insight into methane extraction.

Combined Mud-Cooling, MPD Techniques Enable HP/HT Drilling in Egypt

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210252, “Drilling the Deepest HP/HT Onshore Exploration Well Using a Combination of Mud-Cooling and MPD Techniques: A Field Case Study From the Nile Delta of Egypt Targeting a Mesozoic Carbonate Platform,” by Mahmoud El-Husseiny, Egyptian Natural Gas Holding Company, and Taher Elfakharany, Al-Azhar University. The paper has not been peer reviewed. _ The complete paper reviews the successful application of a mud-cooling and managed-pressure-drilling (MPD) system in a high-pressure/high-temperature (HP/HT) well to explore the potential of the Mesozoic carbonate platform with a pressure ramp and narrow mud-weight window (NMWW) in the Nile Delta. The constant bottomhole pressure (CBHP) variation of MPD in combination with mud cooling was used to drill from the middle of the pressure ramp to the target depth, maintaining the mud-inlet temperature at approximately 50°C. Geological Targets and Geohazards The primary objective of Well T-1 is the edge of a Mesozoic carbonate platform. These carbonates are expected to be high-energy shallow marine deposits with fair reservoir properties (20–50% net-to-gross, 5–10% porosity). The secondary objectives are turbiditic sandstone channels of the Oligocene. These sandstones are expected to have 9–20% porosity and 50–300 md permeability. Potential Middle and Late Miocene geohazards include pressure rampup associated with losses, kicks, and borehole degradation, including tight holes, overpull, and caves; and reported sticking and hangup events. The HP domain begins below approximately 4000 m. Potential Oligocene to Paleocene geohazards include NMWWs associated with losses, kicks, and simultaneous gains and losses (ballooning); borehole degradation, including tight holes, overpull, and caves; and sticking and hangup events. The HP and HT domains begin below approximately 4500 m. Potential Mesozoic carbonate geohazards include possible losses of fractured and pressure-regressed carbonates. Mud-Cooling Technique Concept and Equipment The mud cooler consists of two circuits. In the first, hot mud is circulated through a dual mud cooler using a centrifugal pump. Because of heat exchange through the plate heat exchanger, the mud is cooled and transferred back into the active mud system. The discharge of cold mud takes place upstream of the point where the suction of hot mud occurs. In the second circuit, a fluid mixed with water and glycol is circulated between a dual air cooler and the dual mud cooler using a dedicated pump. When passing through the plate heat exchanger, this mixture of water and glycol is evacuated. When this mixture returns to the dual air cooler, it is cooled using high-performance ventilators. The mud-cooling system features 16 ventilators. The efficiency of the mud-cooling system is adjusted with a number of operated ventilators. The mud-cooling units used in this well consist of two dry air coolers and two sets of air fans (Fig. 1), with each set containing 24 fans. A mixture of 10% glycol and water was used as a cooling fluid.

3D Geological Model for Zubair Reservoir in Abu-Amood Oil Field

The Zubair reservoir in the Abu-Amood field is considered a shaly sand reservoir in the south of Iraq. The geological model is created for identifying the facies, distributing the petrophysical properties and estimating the volume of hydrocarbon in place. When the data processing by Interactive Petrophysics (IP) software is completed and estimated the permeability reservoir by using the hydraulic unit method then, three main steps are applied to build the geological model, begins with creating a structural, facies and property models. five zones the reservoirs were divided (three reservoir units and two cap rocks) depending on the variation of petrophysical properties (porosity and permeability) that results from IP software interpretation. Five wells that penetrate the lower Cretaceous Formation (Zubair reservoir) are used to construct the geological model. ZUB-1 unit considered as the most important zone which have a good petrophysical parameters about 24% for porosity, 800 md permeability, 38% water saturation and 85% net to gross. The initial oil in place is estimated to be about 1.7898*109 STB. Finally, 3D geological model support in improving and estimates the hydrocarbon potentialities in oil field and enhances the production of the field.

Impact of depositional and diagenetic controls on reservoir quality of syn-rift sedimentary systems: An example from Oligocene-Miocene Al Wajh Formation, northwest Saudi Arabia

Tertiary, syn-rift clastic reservoirs offer a unique opportunity to investigate the pivotal role of depositional and early diagenetic controls on reservoir quality. The Al Wajh Formation is a vital exploration target for petroleum in the Red Sea, and is characterized by early, near-surface diagenetic signatures. An integrated petrographic-mineralogical study is conducted to assess the role of depositional factors (e.g., sand grain size and clay matrix) and early diagenetic overprints on reservoir quality. The Al Wajh sandstones are primarily subarkose and lithic arkose, deposited in alluvial fan, braided fluvial, and nearshore environments. Braided fluvial sandstones of the formation have the best quality reservoirs (average porosity: 23.2 %; average permeability: 3025 mD) because of medium to coarse grain size and small proportion of clay matrix, whereas the nearshore sandstones form reservoirs of far lower quality (average porosity: 12.6 %; average permeability: 486 mD) owing to predominantly finer grain size and higher proportion of clay matrix. Clay volume between 10 and 20 % generally reduces the reservoir properties to <10 % porosity and 100 mD permeability. Compaction and grain dissolution are the major near-surface, early diagenetic processes that have strongly affected the sandstones reservoir quality. High mechanical compaction has been recorded in sandstones characterized by abundant matrix content and ductile rock fragments. Dissolution of labile grains (e.g., feldspars) has created secondary, intragranular porosity of up to 13.5 % (average 4.7 %). Kaolinite is the primary authigenic pore-filling clay in the continental units of the formation, whereas detrital and authigenic smectites are the key pore-filling clays in the nearshore units of the formation. Grain-coating smectite (up to 18.7 %; average: 7.1 %) was mainly emplaced through mechanical infiltration and has the potential for inhibiting quartz cementation should deep burial occur. The findings of the study can be utilized for modelling reservoir quality in the subsurface analogue of the Al Wajh Formation in the Red Sea or elsewhere, thereby improving reservoir quality prediction.

Controls of normal diagenesis on poroperm parameters in red beds: examples in Miocene Muddy Creek Formation, Mesquite basin, USA and upper Devonian Old Red Sandstone, Orcadian basin, Scotland

General diagenetic patterns in Miocene Muddy Creek Formation and upper Devonian Old Red Sandstone (ORS) can be characterized as follows: i) early diagenesis characterized by the formation of early hematite, carbonate, and clay cement; ii) burial diagenesis followed by the formation of quartz and feldspar overgrowths, poikilotopic calcite and pore-filling clays; iii) late diagenesis characterized by the formation of late hematite replacing previous poikilotopic carbonate cement. Normal diagenesis has a significant impact on poroperm parameters as indicated by the destruction of pore spaces from cementation and intergranular pressure solution. Early cementation in unburied sandstones of the Muddy Creek Formation reduces sample porosities to 2÷20% of the total rock volume. Cementation destroyed the original porosity of studied sandstones through pore occlusion due to the formation of equant and meniscus calcite cement. Point-count data indicate that the intergranular cement of studied samples ranges between 22 and 44%; in contrast, the intergranular porosities range from 2÷20% of the total rock volume. These consequently indicate that the intergranular volumes that are considered to represent the original porosities of studied samples, ranged from 35÷50% of the total rock volume. Completely pore-occluding poikilotopic calcite cement in the upper Old Red Sandstone reduces poroperm values to as low as 5% porosity and 0.003 mD permeability. Late reddening is caused by replacive hematite cement in the calcite. In addition, normal diagenesis also has an impact on porosity enhancement due to dissolution in the studied red beds. This improves porosity and permeability by as much as 14% and 254 mD in the upper ORS.

Diagenesis and the effects of cataclastic deformation on the Permo-Triassic New Red Sandstone, Isle of Arran, Scotland

Diagenesis in the Permo-Triassic New Red Sandstone, Isle of Arran is characterized by early cementation of hematite, clay, and calcite minerals, followed by burial compaction, quartz, feldspar, and pyrite cementation. Cataclasis post-dated the quartz and feldspar cementation and reduced the grain and pore aperture size in deformed samples. Samples with cataclastic bands typically have 18% porosity and 8.81 mD permeability on average. Whereas, undeformed samples have an average porosity of 22% and an average permeability of 381 mD. Cataclasis was not as important as diagenesis in controlling sandstone porosity and permeability. However, cataclasis resulted in lower porosity and very poor to medium permeability in deformed samples. Cataclastic bands compartmentalize reservoir sands and cause a high heterogeneity in undeformed porous sandstones. Poikilotopic and blocky calcite cement postdates early clay and hematite cement. In addition, burial quartz and feldspar overgrowths also postdate the early clay and hematite. However, the poikilotopic calcite fills in framework grains that have larger void volumes than the grain/grain contacts where quartz overgrowths are present. Cataclasis resulted in fracturing of quartz and feldspar overgrowths. Therefore, the cataclasis occurred after the development of quartz and feldspar cementation. Dissolution postdated the formation of authigenic feldspar and pyrite formation resulted from hematite reduction. The distributions of grain and pore sizes against cumulative mercury volumes in studied samples shows a high level of reduction of grain and pore aperture sizes for deformed samples from single-cataclastic and multi-cataclastic bands. The distribution of apex volumes illustrates that the effective mercury porosity of the multi-cataclastic band sample may be reduced up to &gt; 2 times in comparison to undeformed samples. However, the sample of a thin single cataclastic band has only a slightly lower apex volume in comparison to the host sample.

Preparation and characterization of supramolecular gel suitable for fractured formations

The excellent mechanical properties of supramolecular gel could adapt to the complex reservoir environment and had broad application prospects in the field of oil and gas drilling and production engineering. In this paper, a supramolecular gel based on hydrophobic association and hydrogen bonding was prepared by micellar copolymerization, which could be used to plug fractures and pores in formations. Supramolecular gel was a gel network system with high performance characteristics formed by self-assembly of non-covalent bond interaction. The rheological properties, mechanical mechanics, temperature resistance and swelling ability of supramolecular gel were studied. The results showed that the supramolecular gel had a dense three-dimensional network structure with open and interconnected pore structures, which could exhibit good rheological properties and strong viscoelastic recovery ability. The mechanical properties of the supramolecular gel were excellent, it had a tensile stress of 0.703 MPa and an elongation at break of 1803%. When the compressive strain was 96%, the compressive stress could reach 14.5 MPa. Supramolecular gel also showed good temperature resistance and swelling properties. At the aging temperature of 135 °C, supramolecular gels still maintained good gel strength, and it only took 12 h to reach the equilibrium swelling ratio of 35.87 in 1% NaCl solution. It was also found that supramolecular gel in low concentration saline (1% NaCl solution) showed relatively faster swelling than high concentration saline (25% NaCl solution). The swelling process of the supramolecular gel was non-Fick diffusion (type Ⅱ). This indicated that the organic/inorganic permeability network was well formed. Therefore, the diffusion rate of small molecules could be guaranteed to be equal to the relaxation rate of large molecules before and after the phase transition temperature. In addition to the diffusion of water molecules, the swelling process of the supramolecular gel was also affected by the relaxation of gel network and polymer chain segment, the interaction between water molecules and polymer network and the groups of polymer network and other factors. Supramolecular gel particles could be used as plugging materials for drilling fluids, which had excellent ability to plug formation fractures and pores. The plugging ability of the supramolecular gel was up to 6.7 MPa for 0.5 mm fracture width, and 9.6 MPa for porous media with 5 mD permeability. Compared with HT-PPG gel particles commonly used in oil fields, supramolecular gel particles had better plugging ability on fractures and porous media. The development and application of supramolecular gel had far-reaching significance for promoting the functional application of polymer materials in drilling and production engineering.

Geomechanical assessment of the Lower Turonian AR-F limestone Member, Abu Gharadig Field, Egypt: Implications for unconventional resource development

This study evaluates the unconventional reservoir geomechanical characteristics of the Lower Turonian Abu Roash-F (AR-F) carbonates from the Abu Gharadig field, onshore Egypt, which has not been attempted before. The interval dominantly consists of planktic foraminifera and micrite matrix. The AR-F marine carbonate is organic-rich (0.59–3.57 wt% total organic carbon), thermally mature (435–441°C Tmax) and falls within the oil generation window. The studied interval is very tight with up to 2.6% porosity and 0.0016–0.0033 mD permeability with the wireline log-based brittleness index ranging between 0.39–0.72 which indicates a less brittle to brittle nature. AR-F exhibits a hydrostatic pore pressure gradient with minimum horizontal stress (Shmin) varying between 0.66–0.76 PSI/ft. Safe wellbore trajectory analysis was performed for deviated and horizontal wells to infer the mud pressure gradients required to avoid wellbore instabilities. Based on the inferred in-stress magnitudes and considering an NNE regional maximum horizontal stress orientation, none of the fractures are found to be critically stressed at present day. To produce from the AR-F, hydraulic fracturing is necessary, and we infer a minimum pore pressure increment threshold of 1390 PSI by fluid injection to reactivate the vertical fractures parallel to regional minimum horizontal stress azimuth.

An integrated source rock potential, sequence stratigraphy, and petroleum geology of (Agbada-Akata) sediment succession, Niger delta: application of well logs aided by 3D seismic and basin modeling

We investigated the source rock potential, sequence stratigraphy, and characterized hydrocarbon reservoirs at Otumara field, Niger delta, using integrated 3D seismic, wireline log analysis, and basin modeling. The burial history and thermal maturity were modeled, the reservoirs were delineated, and the petrophysical parameters were also estimated from the wireline logs. The Passey “ΔLog R” method for estimating the preliminary evaluations of the total organic carbon (TOC) from integrating sonic, neutron, and density with resistivity has been used. The results indicate that the primary source rock of hydrocarbons is the Upper Akata Formation, despite a higher TOC percentage in the Agbada Formation. Based on sequence stratigraphy analysis, TA4, TB1, TB2, and TB3 second-order supercycles were obtained in the studied well TD46. The results also revealed that the field has two large net pays with high-quality reservoir facies: a deltaic slope fan at the upper shoreface and a river mouth sandbar at the lower shoreface. Furthermore, the reservoirs were faulted by a series of growing faults that faulted the basin slope. The reservoir facies are characterized by an average of 18% porosity, 1200 mD permeability, 16% volume of shale, and high hydrocarbon saturation of about 85%. Finally, the petroleum system elements have been defined for improved hydrocarbon exploration. In the absence of complete or partial core samples, this case study emphasizes the importance of using wireline logs to estimate organic richness and investigate sequence stratigraphy in clastic sediments.

Rock Type and Pore Throat Radius of Zubair Formation in the W Oil Field: Analysis Utilizing Core and Log Data

The Zubair Formation is a prolific oil reservoir in several southeastern Iraq oil fields. The formation comprises thick sandstones with interbedded shales and siltstones of Lower Cretaceous age (Hauterivian to lower Aptian). The environment of the Zubair Formation consists of fluviodeltaic, deltaic, and marine sandstones. In southern Iraq, the area is subdivided into informal members (oldest to youngest). The Lower Shale, lower sand, middle shale, main pay upper sand, and the upper shale. At the W oilfield, the main pay member is an oil producer. The thickness is of the main reservoir about 100 meters thick. A recent study focused on the Main Pay upper sand, which is divided into three informal units. The upper unit H and lower unit L reservoir units are connected by shale intervals (K unit) that extend throughout the field area laterally. There exist four depositional lithofacies of Zubair Formation fluvial, channel, mouth bar, and prodelta depositional lithofacies. Four Facies were defined according to gamma-ray sandstone, shaly sand, sandy shale, and shale Facies. The Zubair formation has four types of rocks (RRT1, RRT2, RRT3, and RRT4) due to heterogeneity. The RRT1 is characterized by 10%-25% porosities and 10-1000 mD permeability. The RRT2 has a similar porosity range to RRT1, 15%–25%, but an order ofmagnitude lower permeability range from 10-100 mD. RRT3 is considered to have high porosity and low permeability is thought to have great storage but poor flow potential. RRT 3 is characterized by 6%-15% porosities and &lt;10 mD permeability. Meanwhile, RRT4 is considered to have low porosity and low permeability. Various rock types showed in the H unit due to heterogeneity, which composed this unit. The K unit unveiled RRT4 due to shale Facies. The rocks types common of unit L are RRT1 and RRT2 where the L unit mostly ranged from sandstone to shaly sand Facies.

Depositional and diagenetic controls on reservoir heterogeneity and quality of the Bhuban formation, Neogene Surma Group, Srikail Gas Field, Bengal Basin, Bangladesh

This study aims to investigate the controls on reservoir heterogeneity and quality of Miocene Bhuban Formation of the Neogene Surma Group at the Srikail Gas Field, Bengal Basin, Bangladesh. The study integrates wireline log data from two wells with core description as well as petrophysical and petrographic data obtained from 24 core plug samples retrieved from three gas bearing zones. The three zones, namely (from shallower to deeper): D-upper, D-lower, and E-sands, were identified from wireline log interpretation. Based on the extracted cores, the sandstones are classified into three main facies association: 1) coarse grained facies association (CFA) composed of sandstone with parallel lamination, trough, and planar cross bedding; 2) medium grained facies association (MFA) comprises of wavy and flaser bedded sandstone; and 3) fine grained facies association (FFA) consisting of siltstone and shaly sandstone. CFA sandstones, mostly abundant in D-lower and E-sands, were deposited in a high energy distributary channel environment with strong tidal influence while the finer-grained sandstones, mainly present in D-upper sand, were deposited in a low energy distributary channel. The results obtained by integrating core plugs and wireline logs show that best reservoir quality rocks are associated with CFA sandstones which are characterized by GR below 105 API, 15–25% porosity, and 30–100 mD permeability. In contrast, FFA sandstones have lower porosity (<10%) and higher shale content (GR > 125 API). The high energy and strong tidal influence on sandstones of CFA resulted in coarser grain size (and thus larger pores), better sorting and less clay content than the finer-grained, high clay bearing, low energy sediments of FFA. Additionally, petrographic and core plug analyses revealed that mechanical compaction is an important factor that reduces the porosity and permeability with increasing proportions of ductile mineral grains. Other less important diagenetic factors include quartz overgrowth and cement. The findings of this study show that the reservoir quality of the studied field is principally controlled by both depositional environment and mechanical compaction.

Facies analysis and petrophysical investigation of the Late Miocene Abu Madi sandstones gas reservoirs from offshore Baltim East field (Nile Delta, Egypt)

The Nile Delta has become an economically important region of Egypt, because of large-scale natural gas and oil discoveries in recent decades. The offshore Baltim East field is one of the Nile Delta's major gas producers from the upper Miocene clastic reservoirs, but detailed lithofacies and petrophysical analyses of the Abu Madi gas reservoir have not been conducted to date. This study investigates the petrographical and petrophysical properties of the upper Miocene Abu Madi Formation from the Nile Delta to infer the lithofacies distribution, depositional environments, and reservoir qualities of the Level 3 Main and Lower sands. In this work, we used a variety of data sets, including core samples, petrophysical measurements, and well logs, to identify the most important characteristics of these sandstone reservoirs. Both reservoirs are hydrostatically pressured and exhibit a gas gradient of ∼2.26 MPa/km. We have identified six different lithofacies from the two reservoirs. SEM and thin section analyses indicate that trough cross-bedded (F-1), parallel laminated (F-2), and massive sandstones (F-6) are the primary reservoir lithofacies composed of texturally immature subfeldspathic quartz arenites. These sandstones have sharp bases and exhibit fining-upward trends with ripple laminated siltstone (F-3), heterolithic silt and clay (F-4), and laminated claystone (F-5) facies lying on top. We inferred the reservoir depositional environment as fluvial channels and sequence stratigraphically these incised valley-fills represent low stand systems tract. The reservoir sandstone facies show good porosity (10–28%), mostly interparticle. Chlorite coatings around quartz grains are abundant, while pore-filling kaolinite is the dominant porosity-destroying clay phase. Grain dissolution introduced secondary intergranular porosity along the potassium feldspar cleavage planes within the F-1 lithofacies. Porosity, permeability, and reservoir quality parameters (RQI, NPI, and FZI) calculated from routine core analysis indicate that the F-1 and F-6 lithofacies have excellent hydraulic flow properties with >100 mD permeability, RQI>1 μm and FZI >5 μm, while the fine-to very fine-grained F-2 offers poor to fair reservoir quality defined by a wide permeability range of 0.1–2150 mD. The clay and silt-dominated lithofacies (F-3, F-4, and F-5), due to their impervious nature, act as intra-reservoir vertical permeability barriers. The differences in rock composition and facies control diagenesis and physical properties of the reservoir. The results presented, provide further insight into the exploration of the fluvial channel deposits and regional reservoir quality of the upper Miocene Abu Madi Formation of the Nile Delta.

Processes controlling volcanic and epiclastic reservoir formation in a buried polygenetic stratocone

Abstract Understanding the formation of volcanic and epiclastic reservoirs is pivotal for exploring geoenergy resources such as geothermal energy, hydrocarbons, and new CO 2 sequestration and hydrogen storage opportunities. This paper examines the processes controlling the quality of pyroclastic and epiclastic reservoirs of the Kora volcano, an extinct stratocone presently buried in the offshore Taranaki Basin, New Zealand. We conduct detailed seismic reflection interpretation, drillcore lithofacies and wireline-log description, petrographic analysis, and analytical tests to generate a unified framework that explains the formation of volcaniclastic reservoirs from basin to pore-scale. Each stage of construction and degradation of the Kora volcano is associated with particular processes that increase or reduce reservoir quality. Primary processes include quench fragmentation, deuteric mineral dissolution, and epiclastic sedimentation. Secondary processes comprise mineral alteration (mainly meteoric; minor hydrothermal and diagenetic), mechanical stress fracturing (mainly tectonic; minor magmatic and burial deformation), and pervasive biogenic cementation. Epiclastic conglomerates present the highest reservoir quality (average 23% porosity and up to 997 mD permeability), followed by lapilli-tuffs and tuff-breccias. In contrast, bioclastic epiclastic sandstones are typically cemented by carbonates and pyrite. Our models and interpretations will increase understanding of the formation of volcaniclastic reservoirs and aid exploration of geoenergy resources in volcanic terrains.

A Laboratory Approach to Measure Enhanced Gas Recovery from a Tight Gas Reservoir during Supercritical Carbon Dioxide Injection

Supercritical carbon dioxide injection in tight reservoirs is an efficient and prominent enhanced gas recovery method, as it can be more mobilized in low-permeable reservoirs due to its molecular size. This paper aimed to perform a set of laboratory experiments to evaluate the impacts of permeability and water saturation on enhanced gas recovery, carbon dioxide storage capacity, and carbon dioxide content during supercritical carbon dioxide injection. It is observed that supercritical carbon dioxide provides a higher gas recovery increase after the gas depletion drive mechanism is carried out in low permeable core samples. This corresponds to the feasible mobilization of the supercritical carbon dioxide phase through smaller pores. The maximum gas recovery increase for core samples with 0.1 mD is about 22.5%, while gas recovery increase has lower values with the increase in permeability. It is about 19.8%, 15.3%, 12.1%, and 10.9% for core samples with 0.22, 0.36, 0.54, and 0.78 mD permeability, respectively. Moreover, higher water saturations would be a crucial factor in the gas recovery enhancement, especially in the final pore volume injection, as it can increase the supercritical carbon dioxide dissolving in water, leading to more displacement efficiency. The minimum carbon dioxide storage for 0.1 mD core samples is about 50%, while it is about 38% for tight core samples with the permeability of 0.78 mD. By decreasing water saturation from 0.65 to 0.15, less volume of supercritical carbon dioxide is involved in water, and therefore, carbon dioxide storage capacity increases. This is indicative of a proper gas displacement front in lower water saturation and higher gas recovery factor. The findings of this study can help for a better understanding of the gas production mechanism and crucial parameters that affect gas recovery from tight reservoirs.

Novel Scale Inhibitor Extends Treatment Lifetimes in Permian EOR

Background A new extended-release (ER) scale-inhibitor technology showing significantly increased lifetimes has been applied in the Permian Basin. Tomson Technologies and Group 2 Technologies, in partnership with Occidental Petroleum (Oxy), implemented a scale-squeeze program for this carrier system. It allows for fewer squeeze treatments, which results in lower chemical usage, decreased plugging risk, and reduced environmental impact. Squeeze programs are an effective field treatment strategy to prevent scale formation in wells for extended periods of time. However, in some cases, squeeze lifetimes can be short, leading to frequent re-squeezing and production decreases, lowering overall economic recoveries. The ER phosphonate-based chemistry (SI1313) was used in selected wells where incumbent (previous chemical provider) treatment lifetimes were shorter than expected. The incumbent squeeze volumes and additives were used, and the scale-inhibitor (SI) chemistry was replaced with SI1313 to obtain directly comparable results. The wells selected are vertical wells, with predominantly carbonate mineralogy and 14–18% porosity and 9–16 mD permeability. Bottomhole temperature is 105°F (40°C). These wells are under continuous CO2 flooding operations, and the scales of interest are calcium carbonate and calcium sulfate predominantly. The selected wells were targeted to have a good squeeze history for comparison and stable water production. Pre-Job Validation Work Coreflood laboratory experiments were performed to simulate the adsorption and desorption under these specific Oxy Permian conditions. The coreflood showed over 10,000 pore volume (PV) of flow with inhibitor concentration remaining above the minimum effective concentration (MEC) during the entire run. Once greater than two times incumbent performance was reached, the coreflood was stopped, although the return concentration was still above MEC. For reference, corefloods with incumbent phosphonate chemistry under the same conditions usually drop below MEC around approximately 3,000–5,000 PVs. The adsorption of SI1313 to core material was measured during the coreflood experiment and the results show 12.5 mg of inhibitor adsorbed per gram of core material. As a comparison, a typical incumbent phosphonate scale inhibitor adsorbs 1–2 mg of inhibitor per gram of core material. This increase in adsorption is considered a large improvement over traditional chemistry. The carrier platform’s superior adsorption, when combined with controlled desorption, is the basis for extending the lifetimes of scale- inhibitor treatments. The corefloods results validate the ER characteristics expected from SI1313 and allowed for field squeezes to be conducted. Field Application Group 2 Technologies provided SI1313 to be squeezed for Oxy in January 2020, into five vertical conventional wells. The selected wells are in one area where CO2 flooding is in place and there is risk of calcium carbonate (CaCO3) and calcium sulfate (CaSO4) scaling. These wells have had many scale squeezes performed on them, yielding an excellent data set to compare against. The goal of this trial was to show significant lifetime extension compared to previous incumbent squeeze lifetimes.