Reservoir Dip Research Articles

Underground Hydrogen Storage in Porous Media: The Potential Role of Petrophysics

The objective of this study is to showcase the key geological and reservoir engineering parameters that influence underground hydrogen storage, demonstrate the value of some petrophysical data, and show how hydrogen storage differs between depleted gas fields and saline aquifers for reservoir and geomechanical modeling. We utilized numerical simulation modeling to create a base-case model of a synthetic reservoir that accurately represented the hydrodynamic conditions relevant to underground hydrogen storage in porous media. A two-step sensitivity analysis was then conducted. Firstly, we identified the critical parameters that significantly influence the storage and flow of hydrogen in porous media. Subsequently, we analyzed the geomechanical impact of underground hydrogen storage. In addition, we compared the behavior of hydrogen storage to natural gas storage. The study showed that the reservoir depth or current pressure, the reservoir dip, and the flow capacity were the top three factors impacting the optimal withdrawal of hydrogen. The study also revealed that rock displacement and stress changes were important to be monitored, while changes in strain were not significant. If it is assumed that injection occurs in a critically stressed rock, hydrogen injection and withdrawal in saline aquifers could result in more incidence of microseismicity compared to hydrogen storage in depleted fields or even gas storage in depleted fields. This study quantifies uncertainties in data and pinpoints areas where petrophysical measurements could minimize the uncertainty associated with critical parameters relevant to underground hydrogen storage. It also identifies gaps in measurements for hydrogen storage in porous media. These parameters with large uncertainty are crucial for selecting optimal sites for hydrogen storage and detecting subsurface integrity issues when monitoring for underground hydrogen storage in porous media.

Effects of geological heterogeneity on gas mixing during underground hydrogen storage (UHS) in braided-fluvial reservoirs

Hydrogen, as an energy carrier, is at the centre of research attention for its potential advantages over electricity to transport and store excessive renewable energy at the GW scale as part of the energy transition. To store energy at such a large scale and in a seasonal manner, energy storage technologies such as compressed air storage and high-temperature aquifer thermal storage are proposed, where Underground Hydrogen Storage (UHS) in porous reservoirs may be an important technology for hydrogen economy. Research studies suggest the necessity of using alternative gas to hydrogen as cushion gas due to the very low density at reservoir conditions and the high production cost of hydrogen. In addition, the potentially lower development cost of UHS in existing depleted natural gas reservoirs or former sites for underground gas storage compared to that of saline aquifers makes gas mixing a real possibility for future UHS operations. However, this topic is rarely studied, let alone its geological governing factors. In this study, we focus on the most likely geological settings for early UHS projects (Depleted gas fields in high permeability braided fluvial reservoirs) to understand the potential impacts of geological heterogeneity on project economics.To quantify the possible gas mixing induced by macro-scale heterogeneity and find the dominant factors that affect storage performance, in this study, we start by building synthetic high permeability water-gas reservoir model with geological characteristics of braided-fluvial systems often encountered in the oil and gas industry. Then we examine the effects of structural and litho-facies heterogeneity on gas mixing processes during typical UHS projects (10 mol% hydrogen-methane mixture as stored gas) via compositional numerical simulation. Homogeneous cases with different injection/production rates are also part of the sensitivity analysis. The cumulative days hydrogen fraction in produced stream is used as the metric for quantifying gas mixing during this process. Our results show that, compared to the homogeneous cases, macro-scale geological heterogeneity will intensify gas mixing and degrade the hydrogen fraction in the produced stream, affecting up to 15.8% of the recovery in 10 years (6% more than the homogeneous cases). Geological structure (reservoir dip angle and closure area) is a first-order determining factor above facies heterogeneity (braided channel dimensions). It determines the level of methane breakthrough during UHS projects in all the test cases, leading to contrasting gas mixing behaviors. Our study hereby provides a systematic method for evaluating gas mixing in UHS projects and facilitates future UHS techno-economic analysis.

Permeability evolution and production characteristics of inclined coalbed methane reservoirs on the southern margin of the Junggar Basin, Xinjiang, China

The thick and steeply inclined coal seams of the Junggar Basin of Xinjiang, China, are unique with dip angles generally >50° but over the range 0°–85°. Initial and evolving permeability and pressures change drastically around wells down-dip within the steeply inclined reservoir as a result of the depth differential. Hence, the evolution of permeability and fluid pressures during drainage exhibits significant differences from those of flat-lying or even slightly inclined reservoirs. We apply a hydro-mechanical model to evaluate the interaction of two-phase flows of gas and water in the inclined system. The influence of different reservoir inclinations (15°, 30°, 45°, 60°, and 75°) on the evolution of permeability, reservoir pressure, and gas production are explored through finite element modeling of this system. The results show that: 1) Reservoir inclination induces differences in permeability, reservoir pressure, gas content and methane production between the shallower updip reservoir and deeper downdip reservoir. The difference in permeability between the updip and downdip reservoirs is amplified as the dip angle increases and as drainage proceeds in the presence of the varying stress gradient. 2) An apparent asymmetric distribution of reservoir pressures results for wells along dip. The difference in reservoir pressure between the updip and downdip reservoirs intensifies as the inclination increases but lessens with the progress of drainage. The larger the dip angle, the smaller the final reservoir pressure. 3) The pressure reduction in the updip reservoir is larger than that in the downdip reservoir, resulting in the unsynchronized desorption of methane in the updip and downdip reservoirs. Methane within the updip reservoir desorbs preferentially over that in the downdip reservoir. For reservoir dip angles <45° a single peak in methane production rate is apparent but this is supplanted by dual peaks for inclinations >45°. The time gap in gas desorption between the updip and downdip reservoirs results in the “dual-peak” on gas production profile. 4) A larger well spacing along the dip of a more highly inclined reservoir results in more efficient water drainage and gas production. An inverted trapezoidal well pattern is recommended to facilitate the drainage and gas production of reservoirs with significant dip angles.

Assessing the impact of dip angle on carbon storage in saline reservoirs to aid site selection

Reservoir dip angle and permeability significantly impact CO2 plume migration and the amount of secondary phase trapping in storage formations. There is a fundamental trade-off between up-dip plume migration and secondary trapping that can be advantageous, or disadvantageous, for selecting an optimal CO2 storage site. For example, low permeability reservoirs have limited plume migration up-dip, consequently, residual and solubility trapping are also limited. On the contrary, for highly permeable reservoirs, up-dip migration can be fast and extensive, leading to accelerated residual and solubility trapping. By performing a systematic simulation study of plume migration and secondary trapping in reservoirs with a range of permeabilities and dip angles, we found that having a dip angle of at least 1° and permeability of at least 500mD results in up to 88% of the plume being immobilized 100 years post-injection. In reservoirs with a permeability of at least 500mD, we can optimize the amount of immobilized CO2 while limiting the amount of plume migration. As reservoir dip angles increase up to 2° and permeability increases, CO2 plume migration increases progressively, and up to 8x more mass of CO2 can migrate up-dip versus down-dip. At the same time, CO2 solubility in brine and residual trapping work to decrease the plume volume and can immobilize 28% to 90% of the CO2 plume over 100 years post-injection. Five influential parameters were identified that strongly influence the plume volume during the post-injection period for these dipping reservoirs: CO2 saturation, residual gas saturation, CO2 solubility in brine, CO2 density, and formation permeability. We also investigated the impact of simulation grid resolution, the maximum non-wetting phase saturation, and the pore-size distribution parameter on predicted plume behavior. This work provides simple, reliable relationships between key site screening metrics, reservoir dip angle, and permeability to inform the site selection process and monitoring, measurement, and verification (MMV) design.

Analytical model of incremental oil recovery as a function of WAG ratio and tapered WAG ratio benefits over uniform WAG ratio for heterogeneous reservoir

The water-alternating-gas (WAG) operating scheme and reservoir permeability heterogeneity are the main crucial parameters, which highlyaffect WAG displacement process. The novelty of this article lies in the development of an analytical model for WAG incremental oil recovery as function of WAG ratio, viscous gravity ratio and mobility ratio for the stratified heterogeneous reservoir. We have investigated the effect WAG ratio on WAG incremental oil recovery with variation horizontal permeability heterogeneity, vertical permeability anisotropy and dip angle of the reservoir. The critical operating parameters investigations were carried to optimize WAG displacement process in both homogeneous and heterogeneous reservoirs. Finally, we have estimated all the benefits of the most suitable techno-economical WAG operating scheme as tapered WAG (TWAG) over uniform WAG (UWAG). The developed analytical model showsreasonably similar results as numerical simulation. The results of the analytical and numerical analysisshow that the incremental oil recovery accelerated bya decrease WAG ratio. However, this effect is more noticeable at high viscous gravity (VGR). The increase in reservoir dip angle subsequently increases vertical and displacement sweep efficiencies compared to the horizontal reservoir for different WAG ratio. While increasing WAG ratio decreases vertical sweep and increases displacement sweep of inclined reservoir compared to the horizontal reservoir. The increase of oil recoverywas observed by higher Kv/Kh with a lower WAG ratio. However, this effect is less evident at lower Kv/Kh. The WAG ratio with a higher proportion of water is beneficial for the heterogeneous reservoir. The infill implemented before WAG start shows faster oil recovery compared to WAG start first then infill implemented in the heterogeneous reservoir. The TWAG incremental recovery over water flood was 18% in homogeneous and 8% in heterogeneous reservoirs, while EUR was approximately similar to UWAG. The TWAG shows more efficient techno-economic benefits over UWAG due to better economics, faster oil recovery rate, more efficient use of injected gas and reduces response time in both homogeneous and heterogeneous reservoirs.

Initiation mechanisms of radial drilling‐fracturing considering shale hydration and reservoir dip

AbstractRadial drilling‐fracturing is an innovative fracturing technology that achieves superior stimulation effects. This paper develops a model for radial drilling‐fracturing in shale reservoirs, which can predict fracture initiation pressure and failure mode of shale. Compared with published models, this model additionally considers shale hydration and inclinations of boreholes and reservoir. Then, the influences of 7 factors are studied and main conclusions are as follows. First, with the angle between radial borehole and formation strike increasing, matrix failure pressure declines only around 90° and 270°. Bedding tensile failure pressure ascends and then falls back. Bedding shear failure pressure rapidly descends, then reaches a plateau, and finally rebounds. A small or large angle is favorable for bedding tensile failure. Shale tends to crack with bedding shear failure under a moderate angle and with matrix failure only at 90° and 270°. Second, with the enlargement of azimuth difference between the radial borehole and main wellbore, matrix failure pressure periodically fluctuates, forming an inverted W‐shape curve. Bedding tensile failure pressure and bedding shear failure pressure both ascend, then slide downward, and finally rise again. Besides, a small azimuth difference inclines shale to bedding shear failure, and the other failure modes tend to occur when azimuth difference is around 90°. Third, pressures required for all failure modes descend as the dip of shale formation increases. However, the difference in descending rate leads to that the increase of dip angle can incline shale to bedding shear failure. Besides, pressures required for bedding tensile failure and matrix failure decline linearly with the increasing reservoir temperature. Temperature has no impact on bedding shear failure. Hence, matrix failure and bedding tensile failure are more prone to occur in the high‐temperature reservoir. The research provides a reference for field applications of radial drilling‐fracturing in the shale reservoir.

Evaluation of CO2 sequestration and circulation in fault-bounded thin geothermal reservoirs in North Oman using response surface methods

In the past decade, techno-economic feasibility of using CO2 as a working fluid to harvest geothermal energy has been studied and demonstrated in both hot-dry rock and deep brine aquifers. Potential geothermal resources have been suggested by hydrogeological surveys in North Oman area. Many depleting petroleum reservoirs in this area provide excellent candidates as CO2 geologic storage and geothermal reservoirs, considering well-characterized and sealed geological structures and existing on-site infrastructure. In this study, we aim to conduct a comprehensive evaluation of reservoir performances during CO2 sequestration and circulation with possible field conditions in North Oman foreland basin. Continuous response surfaces of performance indicators are developed using 1000 CO2 sequestration-circulation models. Each model input file is assigned a set of values sampled using Latin-Hypercube method from high-dimensional parameter space bounded by ranges of key property parameters of reservoirs, including reservoir dip angle, depth, permeability, thickness, lateral boundaries, bounded fault permeability, and geothermal temperature gradient. Using response surfaces, key performance indicators, including CO2 injection, production, storage, fault leakage, well space, pressure, temperature, produced thermal flux, and lifespan, are quantitatively evaluated corresponding to various reservoir conditions represented by input parameters. The findings provide a quantitative guidance on site selection, geothermal field development and operation, and associated leakage risk assessment and techno-economic analysis for potential CO2 sequestration, geothermal exploration and utilization in North Oman foreland basin and other similar fields.

Analytical model for gravity segregation in WAG displacement recovery of inclined stratified reservoirs

The present study deals with the extension of Stone's model to develop the analytical model of gravity segregated length (distance travelled by injected water and gas together before the complete segregation) and gravity segregated water zone height in water-alternative-gas (WAG) displacement for inclined stratified heterogeneous reservoirs. However, as per our knowledge, until now, all available analytical models of gravity segregation in the WAG displacement process consider the assumption that the reservoir is homogeneous i.e. one-layer system with constant porosity and permeability. In reality, most of the reservoirs are heterogeneous with random variation in permeability due to the variation in the depositional environments, which have a major impact on a vertical sweep in WAG displacement. The analytical models of gravity segregation for dipping stratified heterogeneous reservoir are developed by solving the fractional flow equations of displacement of fluids through MOC (method of characteristics). Then the results of these analytical models are compared with 3D finite-difference compositional reservoir simulation. The developed analytical models give appropriately similar results as 3D finite-difference compositional model. Also, analytical model results show that the complete gravity segregated length (vertical sweep efficiency) increases with an increase in reservoir dip angle and mobility ratio, and a decrease in gravity number, vertical permeability, and horizontal permeability heterogeneity. On the other hand, the gravity segregated water zone height decreases with an increase in reservoir dip angle and gravity number.

Positive measure and potential implication for heavy oil recovery of dip reservoir using SAGD based on numerical analysis

To investigate the effect of the formation dip angle on the heavy oil recovery, a numerical model with the formation dip angle was established based on CMG-STARS. Using the numerical model, the steam chamber evolution and the production index were analyzed for the dip reservoir recovery. The results show that: 1) the steam chamber has an obvious asymmetrical distribution on the injection well; 2) the production index of the dip reservoir is lower than the one of the level reservoir. Furthermore, the reason of low production was analyzed from three aspects, namely, the direct reason, the root reason and the intermediate reason. The direct reason is the higher residual oil for the dip reservoir, especially in the downdip zone. The root reasons are the low steam injection amount and the non-uniform distribution of the injected steam. The intermediate reason is that the dip reservoir has a higher cumulative heat loss, especilly in the updip zone. To improve the low production, the well location was optimized as an effective measure, from the perspective of decreasing the area of the downdip zone. Especially, two evaluation objectives were set to determine the reasonable well locations under the dip unknown and the dip angle known. The well location can be reasonable with 10 m away from the center of the reservoir width under the formation dip angle known (8°). Additionally, the optimal matching relation was given between the well location and the formation dip angle, when considering the formation dip angle unknown. Finally, potential implications were obtained as the formation dip angle changing, including: 1) the steam migrates much farther in the updip zone and much nearer in the downdip zone, as the formation dip angle increasing; 2) the cumulative oil production and the cumulative oil-steam ratio show the decreasing trend as the formation dip angle increasing.

A numerical simulation study on the characteristics of the gas production profile and its formation mechanisms for different dip angles in coal reservoirs

The dip angles of coal reservoirs in China vary greatly, among which the southern margin of the Junggar Basin is generally greater than 50°, rendering it a steeply inclined reservoir (SIR). Within a single well's radius of influence, the different effects of gravity on the up-dip reservoir (UDR) and down-dip reservoir (DDR) of a coalbed methane (CBM) well result from tilting. A large difference exists in reservoir pressure, gas content and permeability levels due to the depth of the UDR and DDR. These differences control the characteristics of the gas production profile (GPP) of SIR wells. In order to study the GPP of CBM wells under different coal reservoir dip angles, ECLIPSE numerical simulation software was used to simulate well production at dip angles of 0°/10°/20°/30°/40°/50°/60°/70°/80°. GPP of the wells in reservoirs with different dip angles in UDR and DDR were compared. The formation mechanism of the GPP was explored by analysing the water saturation, reservoir pressure and gas content characteristics of UDR and DDR. The field case was used to verify the accuracy of the numerical simulation results. From the results of the numerical simulation and field cases, we found a “double-peak” gas production profile (DP-GPP) for the well in SIR. The GPP of UDR is also of a “double peak” type, while that of DDR is of a “single peak” type. These types occur because gravitational forces increase the levels of water migration in UDR and obstruct those of DDR, creating different starting times for methane desorption and different periods of time required to reach peak desorption rates, resulting in a time difference. This time difference in methane desorption observed between UDR and DDR has led to the formation of a DP-GPP. Under a larger drainage area (continuous and homogeneous formation conditions), the continuous outward expansion of the desorption range gradually delays the formation of the DP-GPP and make it appeared later. Since methane supplies are affected by surrounding wells, the stronger well interference is likely to fail to form a DP-GPP. The timing of DP-GPP occurrence is gradually delayed with increasing burial depth due to a decrease in permeability.

Determination of Effective Parameters of Gas Injection in Naturally Fractured Reservoirs by Combination of Reservoir Simulation and Design of Experiment Techniques

Screening analysis is a useful guideline which helps us with proper field selection for different enhanced oil recovery processes. In this work, reservoir simulation is combined with experimental design to estimate main effects and possible interactions of reservoir rock and fluid properties on performance of different gas injection processes in naturally fractured reservoirs (NFRs). Studied parameters include reservoir thickness (h), oil viscosity μo), pore size distribution (λ), horizontal permeability (Kh), storage capacity (ω), reservoir dip, critical water saturation (Swc) and threshold capillary pressure (pct). The recovery factors of different simulation designs are analyzed by use of fractional factorial design (FFD) approach. Finally, the statistical significance of results are evaluated by hypothesis testing and ANOVA, and presented by Pareto and tornado plots. Main effect analysis showed that effective parameters are ordered with respect to their importance as follows: For Methane and nitrogen injection: Kh, dip, Swc, ω, h, μo and λ; threshold capillary pressure showed a minor effect on recovery factor. For Carbon dioxide injection: μo, dip, Swc, ω, h and Kh; Pore size distribution (λ) and threshold pressure were not shown to be statistically significant in this process. Likeness of main effects and parameter interactions for methane and nitrogen injection prove the similarity of dominant mechanisms and characteristics of these processes compared to CO2 injection which seems almost different.

A novel insight of laboratory investigation and simulation for high pressure air injection in light oil reservoir

Due to the precipitous dropping oil price, air injection becomes advantageous to other gas flooding techniques as a result of the low cost. Therefore, this work targeted a light oil reservoir and comprehensively investigated the potential of air injection in this reservoir using experimental and numerical simulation, from which some new insights into high pressure air injection were recognized. Oxidation kinetics of the crude oil were first established using Thermal Gravity Analysis (TG)/Differential Thermal Gravity (DTG), and further validated through a set of history matching. The results indicate that the intense oxidation reaction consumed a great volume of oxygen forming only CO2. Temperature peak occurred after reacting 23 h, revealing that the oxidation reaction is an exothermic process under reservoir conditions and spontaneous combustion might take place. Reservoir dip angle is a crucial parameter governing the oil production and updip injection is generally suggested. Earlier air injection leads to more noticeable incremental temperature effect and also higher ultimate recovery. Air injection seems notably appropriate for rhythm reservoirs. Given a mature reservoir, high-permeability zone would cause gas breakthrough and thus considerably detract the air injection performance. Temperature-resistant polymer gel or foam is suggested to plug thief zones promoting oxidation reactions and air sweep efficiency.

New Technology in a Mature East Malaysian Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 176120, “Success Story: A New Development Concept Utilizing New Advanced Technology in a Very Old Complex Mature Field,” by K.F. Ng, T. Afandi, D. Sa’adon, J. Ja’afar, M.A. Omar, and N.A. Latiff, Petronas, and G.I. Santoso, K. Alang, I.D. Roberts, N. Murad, D. Permanasari, and F. Kutty, Schlumberger, prepared for the 2015 SPE Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 20–22 October. The paper has not been peer reviewed. The T Field, located offshore east Malaysia, is a mature oil field that began its development in the 1970s. Conceptual geological models generally illustrated this field as a retrogradational turbidite setting. It is commonly known that the turbidite channel has enormous geological complexity and, therefore, presents great challenges for successful horizontal-well placement. This paper describes the first job in southeast Asia in developing horizontal-well placement in a turbidite environment. Introduction As of 15 years ago, T Field’s remaining oil deposits were present in the relatively thin turbidite channel complex on the steep-sloping flank of the field. Vertical and slanted wells were drilled to produce the targeted reserves, but post-drilling findings always showed inconsistency in sand existence and distribution because of lateral sand discontinuity. Because of the limited infill reservoirs, high reservoir dip angle, and less-prolific productivity, drilling a highly deviated oil producer along the reservoir dip and steering along its productive layer in the oil leg are found to be the optimal drilling approach. However, high well-placement risks were assessed owing to uncertainties in lateral sand distribution, variable formation dip, and fluid contacts. Evaluating Infill/Redevelopment Potential Some reservoirs located within the western area were believed to carry more re-serves; production data indicated that downdip oil remains untapped by existing producers. An average dipping angle of 13 to 20° and gas-cap-dominant drive suggested that remaining-oil potential could be unlocked only through the addition of the drainage point. Material-balance analysis was conducted, which further verified the earlier deduction by showing that the targeted reservoir contains more oil in place compared with existing book figures and has reserves at approximately twice the amount of previous estimates made from decline-curve analysis. A reservoir model was subsequently constructed. Two types of reservoir models were built in this exercise: a simple grid homogeneous model and a heterogeneous model that was created by referring to a geological depositional concept and to reservoir distribution based on a geostatistical method. Reservoir-modeling and -simulation results are consistent with those obtained from material balance. As expected, the secondary-recovery method will result in an incremental recovery because of the pressure maintenance and better sweep efficiency. However, this recovery is not ideal; the reservoir pressure was halved because of historical production, and lateral discontinuity still exists. Infill drilling was recommended as the best way forward. Well-Concept and -Execution Strategy The feasibility of executing the drilling campaign during the early stage of the study was also considered. In past development campaigns, deviated wells were drilled to penetrate and produce from multistacked reservoirs. The replication of such practices may result in missing the reservoir target because of the high potential of reservoir discontinuity.

Petroleum alteration by thermochemical sulfate reduction – A comprehensive molecular study of aromatic hydrocarbons and polar compounds

Thermochemical sulfate reduction (TSR) alters petroleum composition as it proceeds towards the complete oxidation of hydrocarbons to CO2. The effects of TSR on the molecular and isotopic composition of volatile species are well known; however, the non-volatile higher molecular weight aromatic and polar species have not been well documented. To address this deficiency, a suite of onshore Gulf coast oils and condensates generated from and accumulating in Smackover carbonates was assembled to include samples that experienced varying levels of TSR alteration and in reservoir thermal cracking. The entire molecular composition of aromatic hydrocarbons and NSO species were characterized and semi-quantified using comprehensive GC×GC (FID and CSD) and APPI–FTICR-MS.The concentration of thiadiamondoids is a reliable indicator of the extent of TSR alteration. Once generated by TSR, thiadiamondoids remain thermally stable in all but the most extreme reservoir temperatures (>180°C). Hydrocarbon concentrations and distributions are influenced by thermal cracking and TSR. With increasing TSR alteration, oils become enriched in monoaromatic hydrocarbons and the distribution of high molecular weight aromatic hydrocarbons shifts towards more condensed species with a decrease in the number of alkyl carbons. Organosulfur compounds are created by the TSR process. In addition to the increase in benzothiophenes and dibenzothiophenes noted in previous studies, TSR generates condensed species containing one or more sulfur atoms that likely are composed of a single or multiple thiophenic cores. We hypothesize that these species are generated from the partial oxidation of PAHs and dealkylation reactions, followed by sulfur incorporation and condensation reactions. The organosulfur species remaining in the TSR altered oils are “proto-solid bitumen” moieties that upon further condensation, oxidation or sulfur incorporation result in highly sulfur enriched solid bitumen, which is chemically distinct from pyrobitumen formed by thermal cracking reactions.Although TSR involves the oxidation of hydrocarbons to CO2, prior studies of TSR-altered oils have not identified intermediate products. Using NESI–FTIRC-MS, the presence and distribution of oxygenated species become evident. All oils possess minor amounts of O2 and O4 species, presumable mono- and di-naphthenic acids originating from the source. As TSR progresses, the distribution of oxygenated species shifts towards increasing species with higher oxygen content, up to O8. Similar trends are observed for the SOx species. We hypothesize that these are partially oxidized condensed hydrocarbons and that these species are likely formed by the reaction proposed by Püttmann et al. (1989) for the oxidation of PAHs associated with Kupferschiefer mineralization, whereby hydrocarbons with aryl–aryl bonds incorporate sulfur to form thiophenic species.The rate of TSR is influenced by reservoir temperature and the presence of H2S. Typically, high reservoir temperatures (>140°C) are needed for extensive TSR alteration to occur. Oil from the Gin Creek Field appears to have received a charge of H2S, presumably from TSR alteration of a down dip reservoir, which has accelerated the TSR reaction within a relatively cold reservoir (∼109°C). This condition has allowed for the generation and preservation of abundant sulfur containing species that would be thermally cracked at higher temperatures.

A Statistical Inference Approach for the Identification of Dominant Parameters in Immiscible Nitrogen Injection

Screening analysis is a useful guideline that helps us with proper field selection for different enhanced oil recovery processes. In this work, reservoir simulation is combined with experimental design to estimate the effect of reservoir rock and fluid properties on performance of immiscible nitrogen injection. Reservoir dip, thickness, and horizontal permeability are found to be the most influential parameters. Possible interactions of parameters are also discussed to increase reliability and robustness of screening results. Finally, significance of both main effects and interactions are evaluated by employing a statistical inference approach (hypothesis testing) and results are compared to Pareto analysis.

The Impact of Reservoir Properties on Pseudo Functions: Upscaling of Relative Permeability

Relative permeability is the most challenging parameter during the scale-up process. Dynamic pseudoization approaches are the best methods for upscaling of relative permeability. However, dynamic pseudo functions are dependent to some reservoir properties. In this study, the effects of absolute permeability, PVT properties, vertical to horizontal permeability ratio, and reservoir dip angle on three dynamic pseudo functions of Kyte and Berry, Stone, and transmissibility weight were investigated. Different reservoir properties on a 2-D cross-sectional heterogeneous model were studied. Between the properties were studied, the ratio of vertical to horizontal permeability had the most pronounced impact on all dynamic pseudo functions. Dip angle also had an intensive effect on Stone pseudos.

Effect of operational parameters on SAGD performance in a dip heterogeneous fractured reservoir

Steam Assisted Gravity Drainage (SAGD) has been studied theoretically, experimentally and numerically as a promising EOR process. Most of the simulation works have been conducted microscopically in homogeneous non-dipping models. In this communication, the effect of operational parameters on SAGD performance is investigated in a dip heterogeneous naturally fractured reservoir (NFR) with oil wet rock using CMG-STARS thermal simulator. The results indicate that reservoir dip has unfavorable effects on SAGD performance due to overriding effect. Moreover, less oil saturation of matrix causes steam to penetrate into upper blocks. It has also been observed that reservoir thickness controls operational parameters. Furthermore, the results indicate that there is no need for more preheating due to desired heat communication between well pair. As it was expected, higher steam injection rate leads to more oil production. Besides, longer well pairs have no considerable effects on SAGD performance in dip reservoirs. Besides, because of quick reservoir depletion in injection at high pressure, SAGD is not recommended economically in thinner reservoirs.

CO2 Fate Comparison for Depleted Gas Field and Dipping Saline Aquifer

An important metric for CO2 storage is the CO2 fate plot, which displays the partitioning of mobile/capillary trapped/dissolved/mineralised CO2 as a function of time. The archetype version of this plot (Fig. 1, from the IPCC 2005 report [1]) is idealised. While a simplification is a good way to illustrate physical mechanisms, the problem with this plot is that due to its popularity it is now easily misinterpreted to be a universal plot. However, for actual case studies the curves behave quantitatively and sometimes qualitatively differently from the archetype plot. The reason for this is that reservoir settings are different from case to case, having a profound impact on the characteristic times, shapes, and magnitudes of the CO2 fate curves. The objective of this work is to generate a realistic range of CO2 fate plots, derived from reservoir simulations on simple geometries but with realistic input parameters, expressing the impact of key control parameters. This new range of plots can be used for communication purposes to a wider audience, and also as a Quality Control tool for future modelling studies. Our results bring out major differences between a depleted gas field setting (more generally: structurally closed setting) and a dipping saline aquifer setting (more generally: structurally open setting). In a structurally closed setting the CO2 dissolution and/or mineralisation takes orders of magnitude longer than in a structurally open setting. This result is quite robust under variation of other parameters such as vertical to horizontal permeability, reservoir thickness, reservoir dip angle, relative permeabilities and geochemical variations. Moreover, only a small subset of structurally open cases, and none of the structurally closed cases, leads to CO2 fate plots that are similar to the one in the IPCC 2005 report. Therefore the CO2 fate plot from the IPCC 2005 report should not be used for quantitative statements regarding the relative size and timing of the various CO2 fate categories; for most potential CO2 storage sites such statements are likely to be invalid. Another implication is that for a structurally closed setting the CO2 tends to be relatively static: slow transitions between CO2 fate categories, and (due to structural closure) limited lateral migration of mobile gas. For a structurally open setting, however, the CO2 fate (spatial distribution and trapping category) is much more likely to vary significantly over time due to relatively quick CO2 plume migration laterally and relatively quick conversion of CO2 into the less mobile (capillary trapped/dissolved/mineralised) CO2 fate categories. For structurally open cases, the balance between, on the one hand, the lateral CO2 plume migration speed and, on the other hand, the capillary trapping/dissolution/mineralisation rate, determines the spatial distribution of the mobile CO2 in relation to potential leak paths. Therefore for CCS project screening/design in structurally open cases it is more critical to investigate this balance than for CCS in structurally closed reservoirs.

Developing Flank Areas in a Giant Carbonate Field With Horizontal-Well Placement

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 161591, ’Development of Flank Areas in a Giant Carbonate Field With Optimal Placement of Horizontal Wells,’ by Sameer Khan, SPE, Ali Al-Shabeeb, Zankar Jani, Yousef Azoug, Nguyen Minh, and Harshad Patel, SPE, Zakum Development Company, prepared for the 2012 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Successful development of flank areas depends on accurate reservoir characterization—in particular, water-saturation distribution—in addition to the optimal areal and vertical placement of wells. In relatively thin reservoirs, horizontal wells are generally preferred to increase reservoir contact; the proper spacing and vertical placement of these wells are critical. To test the initial concept in the field, two existing producers were converted into injectors, and pressures were monitored at the offset producers. Introduction The subject oil field is one of the world’s largest offshore carbonate reservoirs and has a production life in excess of 100 years. The field was historically developed with wellhead tower platforms made of steel structures and a combination of vertical and 1-km-long horizontal wells in a five-spot pattern. A new development plan was proposed in 2008 that deployed artificial islands as drilling centers and used extended-reach- drilling technology. In addition, well counts were significantly reduced by deploying longer (3-km) horizontal laterals, referred to as maximum-reservoir-contact (MRC) wells. The development plan comprised both surface and subsurface components, which were effectively integrated to provide maximum flexibility in terms of development options as well as handling of reservoir uncertainties. Because the aquifer support for the subject field is weak, the development consists of a waterflood with line drive to be followed later by gas injection. This island-based plan was approved by shareholders in 2008, and implementation began soon thereafter. The development plan includes a comprehensive subsurface development scheme based on the available data and prediction tools. Development-plan optimization soon began as more data were being acquired and new reservoir models were built. This work is focused on development-plan optimization of two large flank areas of the largest reservoir in the subject field (south and east flanks in Fig. 1). These flank areas contain very large capillary transition zones that, although only a few hundred feet high, extend to several kilometers areally because of very low reservoir dip (1 to 2°) in a 150-ft-thick reservoir. Therefore, appropriate areal and layer placement of MRC wells in flank areas is a critical task that requires careful attention.

Influencing Factor Study of CO&lt;sub&gt;2&lt;/sub&gt;-Assisted Gravity Drainage in Extra-Low Permeability Reservoir

CO2 flooding is an important method of enhancing oil recovery (EOR) in extra-low permeability reservoir, which can resolve the problems of water flooding effectively. The EOR theory and influencing factors of CO2-assisted gravity drainage were studied in this paper. The influencing factors, such as reservoir dip, injection volume, injecting position, well placement and reservoir effective thickness were analyzed and optimized based on the theoretical numerical model which had been established according to Tuha Niuquanhu inclined reservoir parameters. This research indicates that CO2-assisted gravity drainage can effectively EOR if appropriate parameters were adopted. The results of this paper can offer suggestions to similar reservoir development.