Reservoir Compartmentalization Research Articles

Pressure Monitoring of Disposal Reservoirs in North‐Central Oklahoma: Implications for Seismicity and Geostorage

AbstractDisposal of industrial wastewater and activities such as underground sequestration depend upon pressure conditions within deep geologic reservoirs. Sometimes, injection and storage are associated with induced seismicity, suggested to result from reservoir compartmentalization, leakage into faults, or other mechanisms in the subsurface. To understand subsurface pressure conditions within a major regional disposal reservoir, the Arbuckle Group of Oklahoma, we monitored the water levels in 15 inactive injection wells. The wells were monitored at 30‐s intervals, with eight wells monitored since September 2016, and an additional seven from July 2017. All the wells were monitored until early March 2020. Since 2016, hydraulic head decreased in 13 of the 15 wells, proportional to near‐borehole fluid pressure even considering decreasing regional injection volumes during this period. The well pressures respond to three types of perturbations: (i) gravitational fluctuations (a.k.a. solid‐earth tides) (ii) distal and proximal earthquakes, and (iii) injections into nearby wells. Parameterization of tidal responses illustrates that the near wellbore environments have negative fluid flux (i.e., are leaking). Earthquakes cause differing pressure responses from well to well, with some highly sensitive to proximal events, some to distal events, and some apparently insensitive. Injections have variable impacts in some cases masking tidal and earthquake pressure signals. Collectively, there appears to be a threshold injection rate above which well pressure becomes less sensitive to the volume of injections within 15 km. Multi‐scale geological structure and temporal permeability changes are likely controlling the pressure field, indicating leakage of fluids across the system.

Extraction of the three-dimensional architecture of deformation bands from ground-penetrating radar cubes using multiattribute analysis

Fault zones in porous siliciclastic rocks can be dominated by deformation bands (DBs), which are small-scale tabular structures that usually occur as cluster features. DBs can reduce permeability, contributing to the compartmentalization of oil reservoirs and aquifers. DBs cannot be imaged by seismic methods, but can be imaged by Ground-penetrating radar (GPR). Although DBs and host rocks share the same lithology, GPR imaging is possible because DBs can cause small vertical offsets and reduce the amplitude of the GPR signals. We present an automatic approach for extracting the three-dimensional (3D) architecture of DBs from GPR cubes using multiattribute analysis. We used a 200 MHz GPR cube surveyed on an outcrop of a sandstone formation highly impacted by DBs in the Rio do Peixe Basin, northeastern Brazil. The multiattribute analysis is based on edge evidence and sequential ant-tracking, a combination that can identify narrow zones of attenuated GPR signals. Furthermore, the 3D architecture of DBs was extracted as a geobody using an opacity balancing operator. The geological reliability and limitations of the geobody were demonstrated by comparing slices of the geobody with images of exposed DBs in similar positions, in addition to structural measurements obtained in field and in the geobody.

Effect of thermodiffusion on compositional grading in hydrocarbon reservoirs: Insights from field cases and simulations

Heterogeneity of fluid composition in vertical and lateral directions is observed in many reservoirs, known as compositional grading. It is necessary to evaluate the diffusion forces for modeling this phenomenon. In addition to the chemical and gravity forces, the temperature gradient causes mass diffusion. In the present investigation, the accuracy and reliability of the Haase theory and the Shukla-Firoozabadi method in thermodiffusion modeling are studied comprehensively using field samples from light to heavy-oil reservoirs. On the one hand, the Shukla-Firoozabadi model results in compositional grading reduction by thermodiffusion; on the other hand, the Haase theory reveals enhancement and attenuation effects of thermodiffusion depending on reference enthalpy quantification. A new approach, which employs the reference enthalpies of pseudocomponents as tuning parameters, is proposed to improve the results of the Haase theory. The proposed procedure is also validated using field cases. In addition, the experimental field information compared with isothermal and nonisothermal models are studied to answer the question of "how" and to "what extent" thermodiffusion contributes to compositional grading. Results demonstrated the limited attenuation effect of thermodiffusion in light oils, while this phenomenon leads to severe enhancement of compositional grading in the medium and heavy-oil reservoirs. In heavy oils, the thermodiffusion effect is more pronounced on heavy pseudocomponents rather than light paraffinic species. Finally, the practice of compositional gradient model optimization, which is of particular interest to reduce the uncertainty in fluid initialization and to address reservoir compartmentalization, is presented.

Fluid characterization of oil and gas fields: implications for fault and top seal integrity assessment

Integrity of fault and top seal is a key factor that affects hydrocarbon fluid phase distribution in the subsurface. Mapping fluid property distribution can therefore provide important tools towards assessing seal integrity and trapping mechanisms – two of the most critical elements in petroleum systems analysis towards optimzing exploration and development strategies. This is best achieved by proper fluid characterization that integrates fluid geochemistry and pressure–volume–temperature (PVT) data to identify equilibrated and disequilibrated fluid gradients. Fields from Paleozoic and Mesozoic basins in the Arabian Peninsula at different stages of delineation, appraisal, development and management are discussed as examples to demonstrate the role of fluid characterization in aiding the evaluation of top, lateral and fault seal integrity, and in providing insights into the sealing and buffering effects of reservoir heterogeneity on trapping mechanism, fluid distribution and flow capacity. Examples discussed include (1) reservoir heterogeneity controlling fluid distribution and trapping mechanisms in two neighbouring gas fields, (2) geochemical evidence for a lateral seal separating gas condensate region from oil discovered during field development, (3) solid reservoir bitumen atop a giant gas field, (4) selective gas leakage through anhydrite seal, and (5) geochemical evidence for fault-controlled reservoir compartmentalization rather than a hydrodynamically tilted fluid contact in a field at an appraisal stage where PVT data are limited or inconclusive. Put in structural context, seal-related interpretations of the fluid data are aligned with observations from seismic and geological data on the existence of faults with favourable orientations or facies changes. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

Optimal control of multilateral waterflooding wells in carbonate reservoirs with uncertainty consideration

The benefits of adjoint formulation in studying and improving the economic and production viability of reservoir waterflooding problems has been reported in several researches. However, there is little or no recorded report on its use for multilateral wells in uncertain waterflood reservoir conditions. This study aims to investigate the effect of geological uncertainty to multilateral well performance using adjoint formulation in oil reservoir waterflooding. First, an oil reservoir model with uncertainty assumption in permeability, Corey value, and physical dimension in reservoir compartmentalization was developed. Second, an optimal control sequence for the multilateral injection well was developed to optimize the net present value (NPV). The study revealed that with the obtained control sequence, reservoir compartmentalization notably faults in rock structure, significantly influenced the production capacity of multilateral wells which resulted in a higher NPV and oil rate when compared to other uncertainty cases.

Pore Pressure and Compartmentalization of Carbonate Reservoirs in Northern Madura Platform - East Java Basin, Indonesia

Understanding pore pressure characteristics in carbonate reservoirs is essential, because it concerns all aspects of subsurface, drilling, and occupational safety, as well as the environment in oil and gas exploration and exploitation. In this study, the pore pressure regime and connectivity of the carbonate reservoir (compartmentalization) of Kujung and Ngimbang Formations in the northern Madura Platform of East Java Basin are characterized by utilizing direct pressure data and wireline logs from five wells. The result shows that both hydrostatic and slight overpressure conditions are found in these formations, further indicating the presence of carbonate compartmentalization. The magnitudes of overpressure, however, are mostly very low, with an average of ~37 psi. Four compartmentalized carbonates are identified based on the presence of different pressure gradients in the water leg. The slight overpressure in the carbonates is likely owing to pressure transference from overpressured shale at depth. In addition, by using acoustic impedance from seismic, the depositional environments of the carbonates are interpreted as lagoon and tidal flat. These environments support the occurrence of patch reef carbonate buildups in the Kujung and Ngimbang Formations, which later become a good environment for overpressure generation and carbonate reservoir compartmentalization. Keywords: carbonates, compartmentalization, depositional environment, slight overpressure

Case study of mountainous geothermal reservoirs (Kopaonik Mt., southwestern Serbia): Fault-controlled fluid compartmentalization within a late Paleogene-Neogene core-complex

A composite hydrogeothermal survey of the magmatic-metamorphic post-NeoTethyan late Paleogene - Neogene crustal core-complex of the Kopaonik Mt., southwestern Serbian highlands, provides new constraints on the subsurface hydraulic across- and along-fault flow fluid regimes and geothermal anomalies associated with the two shallow reservoirs. The study is involving synergistic approach by combining structural geology, exploratory drilling, temperature logging, hydrochemical and hydrodynamic constraints further illustrating a complex conduit–barrier fault-controlled spatial compartmentalization of the two thermal water reservoir(s). The thermal waters of the Kopaonik Mt. geothermal field are channeled by the major regional faults and associated fracture zones that are crosscutting the volcanics and the adjoining metamorphites. The results show that the subsurface compartmentalization of the active reservoirs, which are supplying the spa town of Jošanička banja, are controlled by a seismically active regional faults (including the fault that is crosscutting the Slanište locality, having N-S trending). Owing to the linear channeling of the fault-controlled reservoirs, in which the main quantitative water circulation takes place, it was possible to identify the thermal fluid flow paths and associated recharge zones (catchments). The Jošanička banja thermal waters reservoir is accommodated at ca. 400–500 m depth, whereas the Slanište aquifer maintains a shallower position. The new surface - subsurface constraints allowed the estimation of the subsurface reservoir elevations, pinpointing the origin of shallow crustal geothermal processes. Of particular importance is better understanding of the subsurface spatial distribution and the ultimate depth of the developing Kopaonik Mt. geothermal field. The new interpretation shows a qualitative agreement with the core-complex-related heat sourcing, as well as the fault-controlled reservoir compartments, impacting the efficient extraction of the thermal waters, in terms of quantity, quality and water temperature.

Multidisciplinary Integrated Approach Unlocks Fracture-Characterization Ambiguity

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213771, “Unlocking Fracture-Characterization Ambiguity: A Multidisciplinary Integrated Approach,” by Ali Abughneej, Mohamed Al-Naqeeb, and Mohammed Al-Ostath, SPE, Kuwait Oil Company, et al. The paper has not been peer reviewed. _ Fracture systems play a significant role in production in the case of tight, low-porosity complex reservoirs. An exploration well in North Kuwait that targeted the Middle Marrat formation encountered uncertainty regarding reservoir compartments in an underexplored field, with minimal offset wells to properly evaluate its potential. A multidomain approach is proposed leveraging different types of expertise to tackle the petrophysical and geomechanical aspects of the fracture system governing the carbonate layer and assess its producibility and qualification for stimulation through hydraulic fracturing. Introduction A comprehensive study was performed on Well A targeting the Marrat formation, a tight, low-permeability carbonate Jurassic reservoir. During the last two decades, the operator has drilled many vertical and deviated wells through this formation. Hydrocarbon production from the closely spaced wells shows a major variation in flow rates, which has been attributed to the presence of uncharacterized fracture clusters as well as the limited understanding of reservoir compartmentalization. To address the challenges of production discrepancy, an innovative multidomain approach was proposed as an integrated solution in an attempt to understand the fracture systems governing the reservoir setting and its compartments and further assess their connectivity and extent to form a perspective on their possible contribution or hindrance to flow. An end-to-end comprehensive work flow was created combining the results of advanced formation evaluation, high-resolution borehole imaging, and state-of-the-art sonic imaging [the 3D far-field sonic (3DFFS) approach], followed by a fracture-stability analysis for the purposes of completion optimization and potential future hydraulic fracture design. Geological Setting Middle Marrat is targeted as the hydrocarbon-bearing zone, consisting of dolomitized oolitic grainstone to packstone facies, reflecting the high-energy inner-midramp shoal depositional environment.

Assessing the viability of CO[formula omitted] storage in offshore formations of the Gulf of Mexico at a scale relevant for climate-change mitigation

We investigate the feasibility of industrial-scale geological carbon sequestration as an effective climate change mitigation technology. We do so by performing numerical simulations of coupled multiphase flow and geomechanics on a representative field-scale geological model in the Gulf of Mexico that could become a typical CO2 storage site. We use our representative model to investigate two potential hazards associated with large-scale CO2 storage: (1) The potential that CO2 might migrate to shallower formations and (2) The potential that CO2 injection might induce seismicity due to destabilization of pre-existing faults. At our study location, we find that extensive distribution of clay minerals in fault zones in combination with large fault throws result in widespread occurrence of low-permeability faults that prevent migration of CO2 outside of the injection interval. Low-permeability faults act as flow barriers and can result in reservoir compartmentalization and pore pressure build-up. For our field-scale geological model, we find that the risk of induced seismicity is controlled by the choice of the injection location with respect to pre-existing low-permeability faults. Our model results indicate that industrial-scale CO2 storage in the Gulf of Mexico is feasible, but that a priori reservoir characterization and the choice of injection location are crucial to mitigate the potential occurrence of induced seismicity and CO2 migration to shallower formations.

Reservoir characterization and geologic modeling of the Lower Cretaceous Muddy Formation at Bell Creek Field, Montana, USA

The Lower Cretaceous Muddy Formation at the Bell Creek Field, Montana, USA, is characterized by a clastic sequence of mixed lithofacies. An integrated workflow was applied to define the reservoir compartments and distribution of petrophysical properties throughout the central and northern areas of the field. The workflow focused on the heterogeneity of the reservoir flow units, diagenetic complexities, and the associated compartments. The compartments play a considerable role in controlling the connectivity and fluid flow through the reservoir. Descriptions of the reservoir properties were used as inputs to a three-dimensional (3-D) geologic model for history matching and prediction of CO2 flooding. History matching of the primary production of the Muddy Formation helped to improve understanding of the distribution of the rock and fluid properties. The simulation model was then used to forecast future CO2 flooding in the study area. Following CO2 injection, the collected production data were utilized to verify the validity of the model by comparing the production forecast with the actual field results. The simulation model successfully predicted the CO2 flood response, pressure, and production data.

Technology Focus: Formation Evaluation (February 2023)

The domain of formation evaluation explores how varied a reservoir could be. In the life cycle of a field, from exploration and production to development, as we hone our knowledge to understand the reservoir, we often explore various subdomains of this discipline at various scales. In this issue, we explore three such subdomains at three different scales. Heterogeneity of reservoir properties, as well as the associated uncertainty, from measured to predicted, is best captured when disciplines are studied at different scales, from concepts to models and, finally, to experiences. Paper URTeC 2021-5434 attempts to understand the dynamics of a basin. This research studies the Wolfcamp formation of the Delaware Basin, where quality of the source rock and thermal maturity is deeply governed by the basin tectonics. The western half of the basin, which was relatively stable through geologic time, shows higher maturity in the source rocks than the relatively active eastern half. This known and observed phenomenon has been reported in various works, from vitrinite reflectance studies to the higher gas/oil ratio in producing wells. The authors explore the possibility of higher resident heat flux from igneous activities in the western part of the basin during the Cenozoic that generated these conditions. This, in my opinion, is the absolute big picture. Knowledge like this helps comprehension of why we see what we see. This is not just an academic exercise; it helps address practical problems in constructing facilities, pipelines, and compressor stations when the field enters the development stage. Once basin-scale regional concepts are established, local reservoir-scale models provide the intellectual infrastructure for the perception of reservoir-scale heterogeneities. Models such as these seek answers from various spectra of measurements. From well logs to cores and from structural maps to production histories, the various subdisciplines all play a crucial role in subsequent hypotheses tests. Applying these conceptual models, then, to modern-day analogs provides justification or critiques of the process for the present and has time and again been the key to the past. In paper IPTC 21225, the authors explore the validity of constructing a variable-scale reservoir model of a submarine fluvial/deltaic system from multidisciplinary data sets. The authors integrate these measurements of various resolutions and granularity, enabling the analyses to pan and zoom on the scales of the heterogeneity. After 20-plus years of production in this field, the knowledge here is still invaluable for understanding the reservoir compartmentalization and, thus, determining infill locations. I am intrigued by the complex nature of these depositional systems and the efforts the authors make to understand them. Once the big picture has been established, it becomes time to put the figurative boots on the ground, or the knowledge to work, for drilling wells and producing fluids. The third choice for this issue, paper URTeC 2021-5410, discusses one of those aspects. Pore-pressure prediction is a crucial exercise in this respect, with a very tight margin for error. In early phases of exploration, when well data are limited if not scarce, safe drilling and well construction often rely on the precision of pore-pressure expectancy and prediction models. Subsequently, as the well matures, understanding changes in pore pressure helps design artificial lift systems, if necessary, to optimize production and maximize the life of the field. In this third paper, the authors challenge some of the practiced notions and empirical parameters that are widely used in pore-pressure-prediction models. One of those, the Biot’s coefficient, is hard to measure, rarely available from experiments, and grossly overgeneralized. The authors discuss the implications of these parameters and the resulting excursion from the true value that overassumptions could make. In my opinion, this is a must-read for any geomechanics enthusiast. I hope the readers appreciate the scales of heterogeneity with which formation evaluation is concerned. The purposes here are beyond purely academic, and research often is burdened by a lack of measured data. Uncertainties can be minimized, however, when knowledge is sought by cross-referencing complementary domains and exploring heterogeneity in variable scales.

Constraining depositional evolution and reservoir compartmentalization in a mixed carbonate-siliciclastic lacustrine system: The Yacoraite formation, Salta Group, NW Argentina

The mixed carbonate-siliciclastic Yacoraite Formation, Salta Group in northern Argentina has been interest of recent studies searching for potential analogues for the South Atlantic pre-sal carbonates. Microbial lacustrine carbonates are important reservoir systems and their characteristics and stratigraphic packaging are a major factor impacting compartmentalization. This study provides sedimentological and facies analyses combined with petrographical, isotope geochemical and petrophysical analyses of lacustrine clastics and carbonates using an example from the Yacoraite Formation (Salta Group) in northern Argentina (Tres Cruces sub-basin).The Yacoraite Formation records the evolution of a lacustrine system responding to basin scale tectonic processes and climatic conditions and is interpreted as a microbially-related mixed carbonate clastic lacustrine system comprising 8 main Facies types, deposited in either a perennial or an ephemeral system. The most dominant architectural elements are: Sandstones with interbedded shales (F1), Shales with interbedded sandstones and siltstones (F2), Thick-bedded oolitic grainstone (F5), Thin-bedded oolitic grainstone-packstone (F6) and Stromatolite boundstone (F8). These facies types allow to differentiate two types of lacustrine environments: Perennial (Stage I) vs Ephemeral (Stage II) intercalated with episodes of continental plains deposition, arranged in three depositional sequences (Yacoraite I, II and III), each recording either transgressive or a regressive-transgressive trend.Carbonate and clastics are arranged in cycles during the Perennial l Stage suggesting that the depositional system responded in patterns attributable to reciprocal sedimentation, whereas, during the Ephemeral Stage 2, spatial coexistence of clastic and carbonate seem to be the case rather that cyclic vertical superposition.Thick-bedded oolitic grainstone and Stromatolites (F5 and F8 respectively) of the perennial lacustrine system show laterally continuous and thick beds with the best reservoir properties. Furthermore, the Sandstones with interbedded shales (F1) are characterized by intermediate values of porosity and permeability, which would not result in permeability barriers. On the other hand, Thin-bedded oolitic grainstone-packstone (F6) of the ephemeral lacustrine system are characterized by a high degree of heterogeneity due to their limited areal distribution and their complex spatial variability with Shales with interbedded sandstones and siltstones (F2).

An Efficient and Straightforward Procedure for Rapid Investigation of Reservoir Compartmentalization by Fourier Transform Infrared Spectroscopy of Asphaltenes

Summary Reservoir compartmentalization is an essential phenomenon in the different life cycles of oilfield production. This concept is crucial for the economic assessment of field development plans because it influences future decisions and designs. Hence, early and fast identification of reservoir compartmentalization is highly appreciated in the oil industry. The routine techniques based on the light-end fraction of crude oil [e.g., gas chromatography (GC) fingerprinting] are relatively time-consuming, high-cost, and sometimes affected by secondary processes. The suggestion of an efficient, straightforward, and rapid technique for obtaining the reservoir architecture, especially in giant and supergiant fields, is an acceptable attempt in the oil industry. Although the concentration of asphaltenes shows a gradient in the reservoir, the chemical composition of these compounds is constant in connected and equilibrated reservoirs. Hence, investigation of the chemical composition of asphaltenes with a precise method for revealing subtle differences comprises the underlying of every efficient method in reservoir continuity assessment. Here, the application of the relative root-mean-square deviation (RMSD) technique on the Fourier transform infrared (FTIR) data was used to compare the structural characteristics of asphaltenes in two case studies (i.e., Ahwaz and Shadegan oil fields) from the Dezful Embayment, southwest Iran. The 12 highest difference characteristic peak ratios were determined in the studied sample suit from the calculated variations in 5 replicates of a sample. The comparison between samples was performed based on these peak ratios, and the RMSD method was used to compare the studied samples. The samples with RMSD values higher than the defined threshold were considered samples with different fingerprints, and these wells will not be communicated during production. Results showed that the Ahwaz and Shadegan fields were subjected to reservoir compartmentalization in the Bangestan reservoir. At least three compartmentalized regions have occurred in the Bangestan reservoir of the Ahwaz field, and two distinct zones are observed in this reservoir from the Shadegan field. The pressure/volume/temperature (PVT) data (i.e., fluid property and composition) and repeat formation tester (RFT) measurements confirmed that these proposed regions in the Ahwaz field are distinct and will not be communicated during production. The FTIR results in the Shadegan field were completely corroborated by PVT and RFT results and indicated two distinct zones with no flow communication during production in the Bangestan reservoir. The obtained results showed that the suggested procedure is robust, trustworthy, simple, rapid, and cost-effective for investigating reservoir compartmentalization.

Micromechanics and Strain Localization in Sand in the Ductile Regime

AbstractCritical processes including seismic faulting, reservoir compartmentalization, and borehole failure involve high‐pressure mechanical behavior and strain localization of sedimentary rocks such as sandstone. Sand is often used as a model material to study the mechanical behavior of poorly lithified sandstone. Recent studies exploring the multi‐scale mechanics of sand have characterized the brittle, low‐pressure regime of behavior; however, limited work has provided insights into the ductile, high‐pressure regime of behavior via in‐situ measurements. Critical features of the ductile regime, including grain breakage, grain micromechanics, and volumetric strain behavior therefore remain under‐explored. Here, we use a new high‐pressure triaxial apparatus with in‐situ x‐ray tomography to provide new insights into deformation banding, grain breakage, and grain micromechanics in Ottawa sand subjected to triaxial compression under confining pressures between 10 and 45 MPa. We observed strain‐hardening at pressures above 15 MPa and strain‐neutral responses at pressures below 15 MPa. Compacting shear bands and grain breakage were observed at all pressures with no significant variation due to grain size, except for minor increases in breakage in less‐rounded sands. Grain breakage emerged at stress levels lower than the assumed yield threshold and more intense breakage was associated with thinner deformation bands. Contact sliding at inter‐grain contacts demonstrated a bifurcation into a bimodal distribution, with intense sliding within deformation bands and reduced but non‐negligible sliding outside of deformation bands, suggesting that off‐band zones remain mechanically active during strain hardening.

Concurrent 21. Presentation for: Conceptual model of the Lower Permian Kingia Sandstone (northern Perth Basin, Western Australia) as an alternative energy resource

Presented on Thursday 19 May: Session 21 The geothermal potential of the Kingia aquifer in the northern Perth Basin has been identified. In order to further assess resource potential, the occurrence, conditions, and properties of the Kingia Sandstone have been considered further. A new regional correlation supports the Kingia Sandstone being a regionally extensive unit deposited along the northern margin of the syn-depositional Dandaragan Trough. The unit is part of a falling-stage to lowstand system containing lower and upper shoreface, coastal, beach, and estuarine sands. Gross Kingia Sandstone thickness varies from 16 m on flanking terraces to at least 71 m in the basin depocenter. At depth, reservoir properties are preserved where iron-rich clay grain coatings inhibit cementation and preserve primary porosity. In such cases, net reservoir ranges from 3 to 58 m thick (18 m mean) and net porosity range is 12–19 p.u. (15 p.u. mean). The prevailing geothermal gradient is ~37°C/km with heat flow in excess of 90 mW/m2. Resultant Kingia aquifer temperatures exceed 115°C. Given the presence of hot, porous Kingia aquifer, the potential for geothermal power generation is strong. Production of Kingia brine to surface facilities allows for power conversion via established binary Organic Rankine Cycle (ORC) technology. A scalable Kingia opportunity could help to meet Western Australia’s decarbonisation aspirations by contributing to the replacement of coal-fired and gas-fired power plants, plus supply of low-carbon power to local urea, hydrogen, and gas projects. An enhanced understanding of Kingia porosity distribution, reservoir compartmentalisation, flow performance, and ultimate energy delivery remain key uncertainties subject to future de-risking activities. To access the presentation click the link on the right. To read the full paper click here

Using Agarwal analytical approach with superposition rate and time solutions to analyze multi and single well systems

There are many RTA (Rate Transient Analysis) methods available to analyze wells producing from unconventional formations. The approach of Agarwal (2010) is one of the RTA techniques which have gained an increasing interest due to its simplicity, flexibility, and wide range of applications. In this study, the approach of Agarwal (2010) was adopted to analyze not only single well systems but also multi-well systems by using three different equations. These equations were then integrated with the principle of superposition rate rather than conventional superposition time. By using two field cases, the accuracy of the proposed approaches was validated with current analytical methods and reservoir simulation. The first case represents a multi-well system in which the wells producing with a fixed flowing pressure were put on production at the same time. The operating conditions were then relaxed in the second case by allowing the wells to have different production starting times and varying production profiles.Additionally, this work examined in details the ability of the superposition rate function in converting various production behaviors to their equivalent constant rate solutions. This research clearly shows the advantage of the superposition rate solution over the traditional superposition time function (material balance time) in maintaining the data order in time. Such an advantage makes it easier for the analyst to observe the production changes in well performance in real normal time.Several case studies were used to show how Agarwal (2010) can be utilized to extract different information from boundary-dominated flow period which are useful in the evaluation of reservoir compartmentalization and the effectiveness of infill drilling campaigns. In addition to that, the application of Agarwal (2010) in terms of frac hits evaluation and refracturing operations encountered during the transient flow period was also examined.

Conceptual model of the Lower Permian Kingia Sandstone (northern Perth Basin, Western Australia) as an alternative energy resource

The geothermal potential of the Kingia aquifer in the northern Perth Basin has been identified. In order to further assess resource potential, the occurrence, conditions, and properties of the Kingia Sandstone have been considered further. A new regional correlation supports the Kingia Sandstone being a regionally extensive unit deposited along the northern margin of the syn-depositional Dandaragan Trough. The unit is part of a falling-stage to lowstand system containing lower and upper shoreface, coastal, beach, and estuarine sands. Gross Kingia Sandstone thickness varies from 16 m on flanking terraces to at least 71 m in the basin depocenter. At depth, reservoir properties are preserved where iron-rich clay grain coatings inhibit cementation and preserve primary porosity. In such cases, net reservoir ranges from 3 to 58 m thick (18 m mean) and net porosity range is 12–19 p.u. (15 p.u. mean). The prevailing geothermal gradient is ~37°C/km with heat flow in excess of 90 mW/m2. Resultant Kingia aquifer temperatures exceed 115°C. Given the presence of hot, porous Kingia aquifer, the potential for geothermal power generation is strong. Production of Kingia brine to surface facilities allows for power conversion via established binary Organic Rankine Cycle (ORC) technology. A scalable Kingia opportunity could help to meet Western Australia’s decarbonisation aspirations by contributing to the replacement of coal-fired and gas-fired power plants, plus supply of low-carbon power to local urea, hydrogen, and gas projects. An enhanced understanding of Kingia porosity distribution, reservoir compartmentalisation, flow performance, and ultimate energy delivery remain key uncertainties subject to future de-risking activities.

High-resolution sequence stratigraphic framework for the late Albian Viking Formation in central Alberta

High-resolution sequence stratigraphic frameworks detail the changes in the orientation and distribution of systems tracts in a basin, making it possible to identify areas encompassing reservoir units that have been previously overlooked. The Viking Formation is a stratigraphically complex unit that accumulated in a shallow foreland basin (Western Canada Sedimentary Basin) during the Lower Cretaceous (late Albian). To date, the Viking Fm has only been described using a low-resolution allostratigraphic framework. Herein, we present a high-resolution sequence stratigraphic framework, and discuss the utility of this framework to further petroleum exploration.Two hundred and ten cores that intersect the Viking Fm were logged and these data were used to develop a facies model for the various sequences of the Viking Fm through central Alberta. The formation is mapped and described using Depositional Sequence IV nomenclature, which includes the recognition and correlation of deposits attributed to one of four systems tracts: falling-stage, lowstand, transgressive and highstand. Four depositional sequences are identified and the architecture of deposits in each sequence are discussed. By carefully mapping these deposits in a high-resolution context, we: i) delineate and refine the mapping of regional trends; ii) correlate valley incision to lowstand shorelines; and iii) provide additional criteria for identifying future reservoir units in a mature basin.Based on the high-resolution sequence stratigraphic framework, four additional stratigraphic plays are identified including: forced regressive shorelines, incised valleys, lowstand shorelines and trangressively incised shorefaces, and new lateral facies relations that potentially could produce reservoir compartmentalization. These additional play types are not the typical reservoirs explored for in the Viking Fm and may have been overlooked as non-prospective.

Sedimentology and reservoir characteristics of delta plain reservoirs: An example from Messinian Abu Madi Formation, Nile Delta

Delta plain sandstones represent one of the major deltaic hydrocarbon reservoir compartments. The present research provides integrated sedimentological, petrophysical, and petrographical analyses of delta plain reservoirs using an example from the gas-bearing Messinian Abu Madi in the central part of the Nile Delta. The Abu Madi reservoir is interpreted as a tidally-influenced, fluvial-dominated delta plain, and it is subdivided into four sedimentological architectural elements: distributary channel, crevasse channel (straight and meandering), crevasse splays, and interdistributary bay fill. Although the distributary channel has the best reservoir quality (HFU 4 and HFU 5), it is characterized by a high degree of heterogeneity due to the complex interaction between fluvial discharge and tidal currents; straight crevasse channels (HFU 3 and HFU 4) are similar to the distributary channel but have relatively fine grain size and small sand body volume. The meandering crevasse channels are of low reservoir quality (HFUs 1 and 2) due to the formation of point bar muddy inclined heterolithics. According to the results, the delta plain reservoirs are microscopically dominated by quartzose, and litho- and feldspathic quartzose microfacies. The common mud-matrix and poorly sorted fabric due to rapid deposition as well as reworking by tidal/wave currents, that represent the main depositional controls on reservoir quality. Meanwhile, dissolution, anhydrite, quartz, and calcite as well as authigenic kaolinite and chlorite clays are the main diagenetic control factors on reservoir quality.

Reservoir Monitoring by Inversion of Reservoir Pressure and Saturation Changes from Time-Lapse Avo Differences and Time-Shifts

The main storage-related challenges for accelerated deployment of CCS are capacity, confidence and cost. These challenges are to be addressed by focusing on improving strategies for monitoring and management of the pore pressure distribution in the CO2 storage reservoir. Pressure-driven decision support protocols are to be developed for safe and cost-effective reservoir monitoring. These protocols will enable the operator to maximize CO2 storage capacity and quickly turn monitoring data indicating non-conformance into plans for corrective actions. A new extended method is developed for inverting and de-noising reservoir pressure and water saturation changes from time-lapse AVO differences and time-shifts for the purpose of CCS monitoring and conformance. Detailed reservoir pressure and saturation fronts are obtained for seismic timelapse data in the Norwegian offshore, honouring reservoir compartments and fault boundaries found in comparative studies. Applications on CCS and non-CCS fields offshore Norway were researched in synthetic and field data cases for purposes of benchmarking, pre-storage analysis, monitoring plans and conformance studies. Back-estimations of pressure and saturation changes were successful for both synthetic and field data and have made this method substantially more credible for field cases and seismic history matching.