Fluid Formation Research Articles

Velocity String Drainage Technology for Horizontal Gas Wells in Changbei

The Changbei gas field is dominated by wells with large horizontal displacement, which have exhibited high gas production performance at an early stage of development. With the decrease in reservoir pressure, the liquid loading in the gas well is relatively high and gas production rapidly decreases. Therefore, suitable drainage measures are required to maintain stable gas production. Based on the characteristics of the unconnected oil jacket of gas wells in Changbei, a velocity string was used for drainage. A critical liquid-carrying model was established to determine the location of liquid loading in horizontal gas wells in Changbei. First, the coefficients of the liquid-carrying model were determined through theoretical analysis of the characteristics of the gas well formation. Then, the depth setting of the velocity string was analyzed. The critical liquid-carrying model was employed to calculate the liquid-carrying flow rate of each section; the calculated flow rates were compared with the actual flow rates to determine whether fluid accumulation occurred in each section of the gas well. Thereafter, with the help of the oil and casing position, the suitable setting position of the velocity string was determined. The formation fluid was driven from the tubing into the casing owing to the increase in the overflow area, based on the principle of reducer fluid mechanics. The fluid velocity in the larger overflow cross-section decreased, thereby reducing the drainage capacity of the gas well and resulting in liquid loading. Finally, a timing analysis was performed. After the formation pressure decreased, the well production and flow rate changes were analyzed by placing two velocity strings of different sizes at different wellhead pressures in the gas well with fluid accumulation. The results indicated that although the velocity string was set at a position suitable for fluid drainage, fluid accumulation still occurred after a production period, thus necessitating replacement deliquification.

AAV8-mediated sVEGFR2 and sVEGFR3 gene therapy combined with chemotherapy reduces the growth and microvasculature of human ovarian cancer and prolongs the survival in mice.

Vascular endothelial growth factors (VEGFs) are major regulators of intratumoral angiogenesis in ovarian cancer (OVCA). Overexpression of VEGFs is associated with increased tumor growth and metastatic tendency and VEGF-targeting therapies are thus considered as potential treatments for OVCA. Here, we examined the antiangiogenic and antitumoral effects on OVCA of adeno-associated virus 8 (AAV8)-mediated expression of soluble VEGF receptors (sVEGFRs) sVEGFR2 and sVEGFR3 together with paclitaxel and carboplatin chemotherapy. Immunodeficient mice were inoculated with human OVCA cell line SKOV-3m. Development of tumors was confirmed with magnetic resonance imaging (MRI) and mice were treated with gene therapy and paclitaxel and carboplatin chemotherapy. The study groups included (I) non-treated control group, (II) blank control vector AAV8-CMV, (III) AAV8-CMV with chemotherapy, (IV) AAV8-sVEGFR2, (V) AAV8-sVEGFR3, (VI) AAV8-sVEGFR2 and AAV8-sVEGFR3, and (VII) AAV8-sVEGFR2 and AAV8-sVEGFR3 with chemotherapy. Antiangiogenic and antitumoral effects were evaluated with immunohistochemical stainings and serial MRI. Reduced intratumoral angiogenesis was observed in all antiangiogenic gene therapy groups. The combined use of AAV8-sVEGFR2 and AAV8-sVEGFR3 with chemotherapy suppressed ascites fluid formation and tumor growth, thus improving the overall survival of mice. Antitumoral effect was mainly caused by AAV8-sVEGFR2 while the benefits of AAV8-sVEGFR3 and chemotherapy were less prominent. Combined use of the AAV8-sVEGFR2 and AAV8-sVEGFR3 with chemotherapy reduces intratumoral angiogenesis and tumor growth in OVCA mouse model. Results provide preclinical proof-of-concept for the use of soluble decoy VEGFRs and especially the AAV8-sVEGFR2 in the treatment of OVCA.

Energy efficiencies and CO2 emissions associated with low-temperature separation technologies for the processing of formation fluid from the Achimov deposits

Three different technologies for the low-temperature separation (LTS) of gas condensate from the Achimov deposits in the Russian Urengoyskoe gas and condensate field were assessed using exergy analyses. The options examined included turbo-expansion and ejection. Thermomechanical exergy values were calculated for material streams and exergy losses and efficiencies were estimated for dedicated equipment used in the LTS. The lowest exergy loss of 4221.2 kW was obtained using turbo-expansion and electricity cogeneration. The carbon release associated with each scenario was calculated while considering different production rates, technological parameters and natural decreases in wellhead pressure. The integral carbon footprint after 40 years of LTS operation was estimated for all cases. A classical ejector-based LTS scheme was shown to produce 1200 t of CO2 emissions over 40 years of operation. This same scheme combined with a turboexpander and electricity generator produced 59% less CO2 in the same period. An expansion-cogeneration LTS scheme was found to be the most effective and ecologically friendly among the various options based on this analysis.

Investigating drilling fluid formulations to penetrate productive horizons with high-viscosity formation fluids

It draws our attention to the processes of interaction between the well and the penetrated permeable formations during its construction, which are largely determined by geological and thermobaric conditions, types of fluid saturating the formation, used technologies and technical means. The article deals with the main problems of well construction intended for the high-viscosity oil production. Laboratory and experimental studies have been conducted to solve these issues, they will help to scientifically substantiate and implement new technologies and technical means to increase productivity and durability of wells intended for production of high-viscosity oil from productive formations with complex thermobaric conditions. In this work, the authors conducted a study of the formulations of flushing fluids to penetrate productive horizons with high-viscosity formation fluids. Based on the results of the laboratory tests, it was decided to use a fresh polycationic solution.

On the time of well transition to industrial production mode

The purpose of the article wasanalysis of the reasons for the different velocity of transition of the "well-reservoir" system from one thermodynamic state to another based on experimental data on time and main energy parameters for the conditions of gas and oil and gas fields. The methods. Experimental determination of the transition time of wells to industrial production mode; and analysis of experimental data. Findings. The transition time of the "well-reservoir" system from one thermodynamic state to another is determined by the internal energy of the reservoir and depends on the energy of external influence and the determining parameters: reservoir pressure and temperature. For traditional reservoirs - collectors, including for reservoirs with low reservoir pressures, it is 104 - 107 s. For formations with high formation pressures, the forecast time for the transition of the well to the mode of industrial production or emergency release of formation fluid is 100 - 103 s. Theoriginality. The work shows that in the case of low-energy impact, structural changes in rocks in reservoir conditions occur under sublimit slow loads at the level of approximately 40...70% of the limit value of the dynamic strength of the reservoir rock. It is experimentally shown that the transition of the "well-reservoir" system from one thermodynamic state to another flows for a time that depends on the internal energy of the reservoir and it decreases from t=104 – 107 s to t=100 – 103 and from ln t = 9.3...14.8 to ln t = 0...6.9 in the case of an increase in the energy of external influence, or reservoir parameters - pressure and temperature. Practicalimplementation. The transition time of the "well-reservoir" system from one thermodynamic state to another is determined by the internal energy of the reservoir and depends on the energy of external influence and the determining parameters: reservoir pressure and temperature, as well as the energy of elastic or elastoplastic deformation of the rock. The practical value is the ability to determine the type of oil and gas deposit based on this parameter and choose equipment.

Dynamics of bubble formation in yield stress fluids in parallelized microchannels

The bubble formation in yield stress fluids in parallelized microchannels is investigated experimentally. Nitrogen and Carbopol gel are used as the dispersed and continuous phases, respectively. Due to the feedback effect of the downstream microchannels, the uniformity and stability of bubble formation strongly depends on the properties of gels and operating conditions. The effect of yield stress on the interface evolution during bubble formation is investigated under different mass factions of Carbopol (0.2 %, 0.13 %, 0.05 %) and flow rates of gas (0.1–400 mL·min−1) and liquid (0.03–0.2 mL·min−1). The activation rate of parallel microchannels for bubble production increases with the decrease in the concentrations of Carbopol. The increase of liquid flow rate and the decrease of gas flow rate benefit the uniformity of bubble formation frequency. However, under the double-channel bubble-generation flow pattern, reducing the liquid flow rate significantly improves the stability of bubble formation.

Geochemical reaction of compressed CO2 energy storage using saline aquifer

During the use of compressed CO2 storage in saline aquifers, complex geochemical reactions may occur, affecting the petrophysical properties of the reservoir rocks and leading to CO2 depletion. In this paper, the geochemical reaction mechanism of CCES-SA was studied numerically with the Yingcheng Group in the southeast uplift area of the Songliao Basin as the study area. The hydrogeological parameters of the target study area were used as the initial parameters for the numerical simulation study, and the CO2-brine-rock geochemical reaction simulation was carried out using the reaction transport model to study the effects of the 20-year geochemical reaction on the physical properties of reservoir rocks and CO2 consumption through numerical simulation. The following results were obtained by analyzing the numerical simulation results. The long-term geochemical reactions dissolved chlorite and feldspar minerals, etc., and also precipitated carbonates and clay minerals, etc., which were consistent with the actual results. Besides, the dissolution and precipitation of the above minerals did not affect the porosity and permeability of underground aquifers and did not have adverse consequences for extraction. At the end of 20 years of inter-seasonal energy storage, the percentages of CO2 captured in gas, aqueous phase and minerals were 27%, 65% and 8%, respectively. During storage, it was recommended to inject CO2 appropriately during closure to maintain gas phase CO2 content and pressure. During the production process, the acidified formation fluid came into contact with the inner pipe, increased the risk of wellbore corrosion. When selected materials for wellbore materials, it was recommended to choose corrosion-resistant pipes. What was studied in this paper could provide a theoretical reference for underground energy storage projects involving fluid-rock interactions.

Pore morphology effect on elastic and fluid flow properties in Bakken formation using rock physics modeling

Unconventional geo-resources are critical due to their important contributions to energy production. In this energy transition and sustainability era, there is an increased focus on CO2-enhanced oil recovery (CO2-EOR) and geological CO2 storage (GCS) in unconventional hydrocarbon reservoirs, and the extraction of hot fluid for energy through enhanced geothermal systems. However, these energy solutions can only be achieved through efficient stimulation to develop a complex fracture network and pore structure in the host rocks to extract heat and hydrocarbon, or for CO2 storage. Using Bakken formation well data and rock physics models, this study aimed to identify the post-depositional effect of pore structure on seismic velocity, elastic moduli, and formation fluid; and further predict the best lithofacies interval for well landing, and the implications for fluid (gas, oil, and water) recovery in naturally- and often systematically-fractured geosystems. The KT and DEM models' predictions show distinct formation intervals exhibiting needle-like pores and having higher seismic velocities (Vp and Vs) and elastic moduli (K and µ), relative to other formation intervals that exhibit moldic pores. At the same fluid concentration, the needle-like pores (small aspect ratios) have a higher impact on elastic moduli, Vp, and Vs than on the moldic spherical pores with all other parameters held constant. Vp is affected more than Vs by the properties of the saturating fluid (gas, oil, or water) with Vp being greater in Bakken formation when it is water-saturated than when it is gas-saturated. Vs exhibit the reverse behavior, with Vs greater in the gas-saturated case than in the water-saturated case. Further, analyses suggest that the middle Bakken formation will have a higher susceptibility to fracturing and faulting, and hence will achieve greater fluid (oil and water) recovery. Our findings in this study provide insights that are relevant for fluid production and geo-storage in unconventional reservoirs.Article highlightsIntegrated well log data and rock physics models.Investigated the effect of changes in pore structure on elastic properties and fluid flow in shale.Increase in porosity causes a reduction in elastic moduli and seismic velocities.Vp is more affected by pore geometry than Vs depending on density and properties of saturating fluid.Lithofacies with needle−like pores are more susceptible to fracturing than lithofacies with intragranular pores.

Mediating Infrastructural Discipline: Established Practices and Changing Structures of Dar es Salaam’s Transport Sector

This article discusses the interplay of urban transport infrastructures and their need to and of discipline. Drawing on participatory observation, ride-alongs, and interviews, it elaborates the case of BRT introduction in Dar es Salaam and illustrates how various humans and nonhumans needed to be disciplined so that the Dar es Salaam Rapid Transit system could become operational. Referring to the conceptualizations of mediating technologies (Latour, 1994) and disciplinary devices (Ureta, 2012), this article elaborates how the new transport system disciplines its environment, and how it is itself disciplined through different norms and materialities. However, discipline did not realize as planned. De-scriptions (Akrich, 1992) of the system’s disciplining technologies occurred, as practices turned out differently. New forms and effective combinations of established practices and changing structures have led to fluid formations of urban transport. Two perspectives enable to deeply understand this transitional process. First, a sociotechnical perspective shows how agency has been (re)distributed and mediated through technologies and artefacts that were implemented to secure smooth bus operations. Second, a historical perspective elucidates how previous and prevalent practices of Tanzania’s minibus system and other road users impacted the formation of DART. The article hence demonstrates that technological innovation and spatial reorganization do not only lead to new forms of discipline, but to ongoing mediations and negotiations of transport practices.

Curcumin loaded gold nanoparticles–chitosan/sodium alginate nanocomposite for nanotheranostic applications

A solvent casting technique was used for the preparation of biomimetic nanocomposites scaffolds at three various concentrations of Curcumin loaded gold nanoparticles (Cur-AuNPs-1, 1.5, and 2 ml) as filler materials with chitosan-sodium alginate composite. The physico-chemical properties of prepared Cu-Au NPs and biomimetic nanocomposites were analyzed using various characterization techniques. In vitro biocompatibility of biomimetic nanocomposites are determined using simulated body fluid for biomineralization property, HAp formation and phosphate buffer saline (PBS) for swelling property, protein adsorption. Antibacterial activity of Cur-Au NPs and their nanocomposites carried out against Escherichia coli (E. coli) and Staphylococcus aureus. In vitro cytotoxicity of Cur-AuNPs is identified against UC-6 and MDA-MB 231 cell lines. The use of above studies and activity of Cur-AuNPs with contain biomimetic nanocomposites can adoptable for nanotheranostics.

Simulation study of chemo‐mechanical impacts of CO2injection in morrow b sandstone reservoir

AbstractThis study investigates the impacts of geomechanical and geochemical changes on carbon storage in a partially depleted oil reservoir, using results from four different coupled simulation models. Models were used to examine the relative importance of storage mechanisms, and how changing reservoir parameters might affect these mechanisms through time. The study uses data from a Morrowan sandstone reservoir in the Farnsworth Unit (FWU), Ochiltree County, Texas which is currently undergoing CO2enhanced oil recovery (EOR). Partially depleted oil reservoirs such as the FWU offer attractive carbon utilization and/or storage targets because of existing infrastructure and economic benefits from incremental oil recovery as well as tax credits. However, prediction of storage capacity or long‐term fluid migration in these fields can be difficult because of the wide variation in formation fluids and operational histories that may have undergone. CO2injection can cause complex geomechanical and geochemical responses in a reservoir as a result of interplay between dynamic changes in pore pressure, reservoir temperature, fluid composition, and interactions between formation fluids, CO2, and reservoir rock. Thus, multiple coupled numerical simulation models must be developed and used to more precisely understand what CO2storage mechanisms are most significant, as well as the long‐term fate of the stored CO2. Our study used results from hydrodynamic, coupled hydro‐geomechanical, coupled hydro‐geochemical, and coupled hydro‐geomechanical‐geochemical models to examine how changes in geomechanical and geochemical properties can impact the injectivity or storage capacity of CO2. Models simulated historical field operations and then forward‐modeled a water‐alternate‐gas (WAG) operation for 20 years, followed by a 1000‐year post‐injection monitoring. The work demonstrates that in this specific reservoir, geomechanical impacts appear to be more significant than any geochemical processes, which showed minimal impact on reservoir properties. Furthermore, these simulation scenarios corroborated other studies showing more than 90% of CO2injected are being stored and will remain stored in the reservoir. The study was able to draw on a rich set of data from this currently operational project for the work. Because the Morrow is a widespread oil‐bearing reservoir in the midcontinent of the United States and is fairly typical of many sandstone reservoirs elsewhere, the study has significance beyond the boundaries of our field area. © 2022 Society of Chemical Industry and John Wiley & Sons, Ltd.

Transosseous Reconstruction of the Myofascial Layer After Suboccipital Craniotomy to Reduce the Rate of Pseudomeningocele Formation and Cerebrospinal Fluid Leak: A Technical Note

Transosseous Reconstruction of the Myofascial Layer After Suboccipital Craniotomy to Reduce the Rate of Pseudomeningocele Formation and Cerebrospinal Fluid Leak: A Technical Note

Coupled tripartite investigation of breaker fluid invasion and impact on hydrocarbon recovery in sandstone reservoirs

Breaker fluids are designed to dissolve filter cakes by breaking their long-chain molecules, thereby removing solid deposits on the wellbore wall. Although breaker fluids are not intended to infiltrate the hydrocarbon reservoir, they can invade and cause formation damage by altering sandstone reservoirs' wettability and relative permeability. This can lead to a reduction in the overall reservoir performance. This study coupled tripartite methods to investigate the potential impact of breaker invasion and transport in hydrocarbon reservoirs and its multiscale effect on the performances of sandstone reservoirs. We utilized experimental, analytical, and numerical methods to assess and predict the susceptibility of reservoirs to breaker fluid invasion and transportation. Our experimental and empirical investigations considered varying breaker fluid formulations to evaluate the effects of breaker fluid concentration, formation temperature, and solution gas-oil ratio (GOR) on residual-oil saturation (ROS) and oil-water relative permeability. By adopting the ROS and relative permeability associated with the 50% v/v breaker fluid mixture, the performance of the hydrocarbon reservoir was numerically simulated under the limiting scenarios of no-invasion, moderate-invasion, and deep-invasion of breaker fluid. The results indicate a positive correlation between breaker fluid concentration and ROS, highlighting the risks that breaker fluid invasion and deep infiltration pose to hydrocarbon recovery. Further, results show that both live-oil condition (LOC) and dead-oil condition (DOC) reservoirs are susceptible to the detrimental impacts of breaker fluid infiltration, while their invasion can reduce hydrocarbon recovery in both LOC (−6%) and DOC (−28%). The multi-scale effects on reservoir performance are more pronounced at near-wellbore and DOC than at far-field and LOC. Findings from this work provide valuable insights into the complexity of breaker-fluid invasion in sandstone reservoirs and the mitigation of associated risks to reservoir performance.

Research on Gas Channeling Identification Method for Gas Injection Development in High-Pressure Heterogeneous Reservoir

In a typical ultra-deep high-temperature and high-pressure heterogeneous reservoir in Xinjiang, gas channeling quickly occurs during gas injection because of the heterogeneity of the reservoir, the low viscosity of gas injection, and the high gas-oil fluidity ratio. The identification and prediction methods of gas channeling in gas injection development were studied. First, gas channeling discrimination parameters were determined by the numerical simulation method. According to the ratio of gas to oil produced and the composition of oil and gas produced, the flow stages of formation fluid were divided into five regions: gas phase zone, two-phase zone, miscible zone, dissolved gas and oil zone, and original oil zone. The basis for gas channeling identification (namely, the field characterization parameters for gas channeling discrimination) was discovered through analysis and the knowledge of the operability of field monitoring data as the following two parameters: (1) the C1 content rising again on the previous platform when the trailing edge of the two-phase zone is produced and (2) the continuous rise of the gas-oil ratio in production. Then, considering the original high-pressure characteristics of the reservoir, the field characterization parameters of gas channeling under different formation pressures in the exploitation process (namely, C1 content and gas-oil ratio) were simulated and determined. Thus, a gas channeling discrimination method was established for gas injection development in ultra-deep high-temperature and high-pressure heterogeneous reservoirs. According to this gas injection approach, a gas channeling discrimination method was developed, and the field gas channeling judgment was carried out for a gas injection effective D1 well. The results of gas tracer detection were compared to verify the accuracy of this method, leading to strong support for this method in slowing down the gas channeling.

A stable interface-preserving reinitialization equation for conservative level set method

Existing artificial compression based reinitialization approach for conservative level set method has a few drawbacks, like distortion of fluid–fluid interface and formation of unphysical fluid patches away from the interface. In this paper, a novel reinitialization approach has been presented which circumvents these limitations by reformulating the existing reinitialization equation. The new reinitialization equation by design ensures that the interface contour is kept invariant under the action of level set reinitialization. The unphysical patch formation away from the interface is also resolved here by avoiding the use of ill-conditioned contour normal vectors. Owing to the use of much simpler terms, a significant reduction in the numerical computations is achieved with the new reinitialization equation. The new reinitialization equation also enables one to choose a larger time step during the reinitialization iteration, leading to an overall reduction in computational efforts. In order to evaluate the performance of the present formulation, a set of test problems involving reinitialization of stationary level set functions is carried out first. Then, the efficacy of the proposed reinitialization approach is demonstrated using a set of standard two-dimensional scalar advection based test problems and incompressible two-phase flow problems. Finally, the ability to deal with complex mesh types is demonstrated by solving a test problem on an unstructured mesh consisting of finite volume cells having triangular and quadrilateral shapes.

Prediction of nuclear magnetic resonance porosity well-logs in a carbonate reservoir using supervised machine learning models

Porosity estimation is a fundamental input for reservoir management and petrophysical characterization, and this feature is usually estimated based on laboratory measurements or through the use of well-logs. As an important resource for porosity quantification, nuclear magnetic resonance (NMR) well-logs are extremely useful; they allow geologists and petrophysicists to rapidly quantify different types of porosities (including total, effective, and free fluid porosity), and to perform a full formation evaluation and a reservoir quality analysis. However, the activation of wireline tools, the signal-to-noise ratio, the environmental conditions, and the characteristics of the formation fluid can create expensive and adverse conditions for subsurface acquisition. This research aims to develop machine learning models for the creation of synthetic NMR well-logs, assisted by auxiliary well-logging features. Four supervised models: multilayer perceptron neural network, AdaBoost, XGBoost, and CatBoost, comparing the adjusted R2 and RMSE. Of these, the CatBoost regressor provided the most highly optimized model. It was able to reduce local dissimilarities with the real dataset, and returned a better global metric score, yielding an adjusted R2 of 0.87 and an RMSE of less than 0.01. Moreover, all of the machine learning models provided substantial improvements in total porosity estimation, particularly compared to conventional empirical calculations based on density and sonic well-logs. An improvement of 0.5520 in the adjusted R2 was achieved for the density porosity, and 0.2 for the sonic porosity. The differences between real NMR well-logs and the machine learning outputs were in general less than 5%, for most of the well-logging interval. In addition, a tree boosted porosity model based on well-logs is presented for the first time, and the contributions and impacts of the input features on the model predictions are explored. Finally, the behaviors of the linear and nonlinear features of the model are examined, which allows us to better understand the complex relationships among the features and the dataset used.

Improving the anti-collapse performance of water-based drilling fluids of Xinjiang Oilfield using hydrophobically modified silica nanoparticles with cationic surfactants

Wellbore instability, especially drilling with water-based drilling fluids (WBDFs) in complex shale formations, is a critical challenge for oil and gas development. The purpose of this paper is to study the feasibility of using hydrophobically modified silica nanoparticle (HMN) to enhance the comprehensive performance of WBDFs in the Xinjiang Oilfield, especially the anti-collapse performance. The effect of HMN on the overall performance of WBDFs in the Xinjiang Oilfield, including inhibition, plugging, lubricity, rheology, and filtration loss, was studied with a series of experiments. The mechanism of HMN action was studied by analyzing the changes of shale surface structure and chemical groups, wettability, and capillary force. The experimental results showed that HMN could improve the performance of WBDFs in the Xinjiang Oilfield to inhibit the hydration swelling and dispersion of shale. The plugging and lubrication performance of the WBDFs in the Xinjiang Oilfield were also enhanced with HMN based on the experimental results. HMN had less impact on the rheological and filtration performance of the WBDFs in the Xinjiang Oilfield. In addition, HMN significantly prevented the decrease of shale strength. The potential mechanism of HMN was as follows. The chemical composition and structure of the shale surface were altered due to the adsorption of HMN driven by electrostatic attraction. Changes of the shale surface resulted in significant wettability transition. The capillary force of the shale was converted from a driving force of water into the interior to a resistance. In summary, hydrophobic nanoparticles presented a favorable application potential for WBDFs.

The importance of fault damage zones for fluid flow in low-permeable carbonate rocks – fault-related compaction fronts in the Danish North Sea

This study documents the timing and driving forces of the formation of fault-related compaction fronts in the Upper Cretaceous to lowermost Paleogene Chalk Group in the southern Danish Central Graben, based on the integration of 3D seismic, petrophysical log and clumped isotope data. The compaction fronts reflect zones in the low-permeable Chalk Group that underwent time-transgressive fault reactivation and pore fluid venting driven by movements of deeper salt and inversion movements. The fault-damage zones formed narrow permeability fairways that facilitated better drainage of compaction-driven pore fluids trapped in the matrix, eventually resulting in preferential mechanical compaction of the chalk. Salt doming during the Paleocene – Early Eocene, possibly linked to regional inversion tectonics, led to an initial phase of fault reactivation, offsetting the entire Chalk Group; pockmarks within this interval indicate release of pressurized fluids on the seafloor. Clumped isotope data from calcite-cemented veins associated with these fault-damage zones indicate precipitation from fluids that likely originated from Lower to Middle Jurassic strata at the root of these faults some 1500 m below the Chalk Group. Local thickening of the Paleocene to Lower Miocene Rogaland and Hordaland Groups matches a 20–50 m thinning of the chalk within the compaction fronts. This indicates that preferential drainage and compaction continued as the chalk became buried with clays, which became affected by polygonal-faulting causing episodic leak-offs. The results indicate that fault damage zones in low-permeability rocks may initially act as permeability fairways, but the improved drainage of formation fluids may over time cause preferential mechanical compaction and calcite precipitation. At present, the fault-related compaction fronts form low-porosity chalk bodies that may have acted as seals and/or re-directed fluid migration. The results have important implications for static and dynamic reservoir models, also in the light of Carbon Capture Storage and geothermal energy extraction and storage.

Finite Element Simulations of Fluids Leakage through the Faulted Reservoir

Carbon dioxide (CO2) capture and storage (CCS) in geological formation as a supercritical fluid is a viable option to reduce anthropogenic greenhouse gas emissions. Due to the density difference between CO2 and formation fluid, CO2 shows a buoyant tendency. Thereby, if CO2 migrates towards the fault in a compromised faulted reservoir, it may escape the storage reservoir. Therefore, it is essential to predict fluids leakage through the faulted reservoir into the aquifer, associated pressure development, and fluids properties over time to assess associated risk and quantification of leakage. We present finite element simulations of miscible fluids flow through the faulted reservoir to elucidate this behavior. There are very few attempts to model multicomponent fluids non-isothermal model during phase change including the Equation of State (EoS) which we addressed by coupling the mass balance equation of fluids, the fractional mass transport, and the energy balance equation. To obtain fluids mixture thermo-physical properties, we used the Peng-Robinson EoS. For validation of the coupled formulation, we compared the simulation results with Ketzin Pilot project field monitoring data, which shows good agreement. A faulted reservoir comprised of five layers is used to investigate fluids leakage through a compromised reservoir. These layers are a CO2 storage reservoir, overlain by alternating caprocks and aquifers. We also considered three different CO2 injection rates to study the injection rate effect to assess the pressure buildup during injection process. We present the thermal effect by comparing the isothermal and the non-isothermal conditions. For the latter case, we assumed three different thermal gradients. Additionally, to assess the fault aperture effect, we studied three different apertures. We observed that developed pressure and fluids properties have effects on injection rates, temperature gradient, and fault aperture. Additionally, such responses in the near-field and the far-field from the injection well are critical to assess the risk, which we discussed in this paper.

Pressure transient analysis of horizontal wells in multibranched fault-karst carbonate reservoirs: Model and application in SHB oilfield

Current flow models for fault-karst reservoirs are mostly described as a single fault formation, which cannot be applied in recent-developed multibranched fault-karst reservoirs. This paper established a novel analytical model to investigate pressure response behavior of a horizontal well in multibranched fault-karst reservoirs. The model is able to describe the influence of the physical properties and spatial structure of fracture-cave system on pressure transient response. The flow model considers different flow behaviors in each region, which includes Darcy flow (gravity included) in fault-fracture, large-scale storage flow in karst-cave, and Poiseuille-law-based horizontal laminar flow in the horizontal wellbore, respectively. These assumptions enable the model to match complex situations in multibranched fault-karst reservoirs. Then, the model was retrograded to compare with a single fault-karst reservoir model to verify its accuracy. Further, the solutions were graphed on log-log plots, and we discussed the effect of fluids mobility, formation storability, and structure characteristics (e.g., length, angle, depth, distance) of fracture-cave branches on transient pressure responses. Results show that (a) the number of fracture-cave branches in a reservoir can be directly observed by counting the number of V-shaped appearances on the pressure derivative curve. (b) The exact shut-in time when V-shape appears is affected by volume and distance between two neighboring fracture-cave branches. (c)The characteristics of the V-shape are affected by fluid mobility, formation storability, and length of fracture region. (d) The slope of the pressure derivative curve in the boundary-dominated flow regime can be used to evaluate the gravity effect. (e) The pressure response behavior exhibits a near-well effect when a horizontal well commingled production in the multibranched fault-karst reservoir. Finally, we applied our model and resulting observations to analyze pressure build-up data tested from SHB Oilfield, which demonstrated a workflow to identify the number of fault-karst branches and also to estimate reservoir properties.