The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Alan, Cihan (Istanbul Technical University) | Cinar, Murat (Istanbul Technical University) | Onur, Mustafa (University of Tulsa)
Abstract The objective of this paper is to investigate the estimation of layer permeability, skin, and inflow profile from observations of production-logging-tool (PLT) and/or distributed temperature sensing (DTS) for a multilayered system where the layers communicate only through the wellbore. To achieve this objective, we develop a thermal, transient coupled reservoir/wellbore simulator that numerically solves transient mass, momentum, and energy conservation equations simultaneously for both reservoir and wellbore. The simulator accounts for the Joule-Thomson (J-T), adiabatic expansion, conduction, and convection effects for predicting the flow profiles across the wellbore. A comparison of the developed model with a commercial simulator is provided for the single-phase fluid flow of oil or geothermal brine from partially penetrating vertical or inclined wells with distinct fluid and formation properties. A sensitivity study on transient pressure, rate, and temperature profiles to identify the effect of the layer petrophysical properties and the layer thermophysical parameters is also conducted through synthetically generated test data sets from the developed simulator. In addition, nonlinear parameter estimation with the use of both profiles is shown to be useful to reveal permeability and skin information about individual layers. The results show that temperature transient data are more reflective of the properties of the near wellbore region, while wellbore pressures are determined more by average reservoir parameters. The simulator proves practical for designing a PLT test provided that limitations such as single-phase fluid flow having vertical or inclined well equipped with a thorough fluid characterization (EOS) are met. Such design tests may provide a good source for cross-checking PLT flow profiles and validating the fluid contributions from layers that are open to flow. It is often that the spinner of the field PLT tool does not operate properly at very low flow rates. Also, the spinner may fail to calculate and construct PLT plots accurately at very high flow rates. To the best of our knowledge, this is the first study that presents a coupled transient reservoir/wellbore model for predicting layer permeability, skin, and inflow profile of a well from observations of pressure, temperate, and/or rate data from production-logging-tools (PLTs) and/or distributed temperature sensing (DTS) fiber optic cables.
Abstract If hydrogen is stored in depleted gas fields, the remaining hydrocarbon gas can be used as cushion gas. The composition of the back-produced gas depends on the magnitude of mixing between the hydrocarbon gas and the hydrogen injected. One important parameter that contributes to this process of mixing is molecular diffusion. Although diffusion models are incorporated in latest commercial reservoir simulators, effective diffusion coefficients for specific rock types, pressures, temperatures, and gas compositions are not available in literature. Thus, laboratory measurements were performed to improve storage performance predictions for an Underground Hydrogen Storage (UHS) project in Austria. A high-pressure-high-temperature experimental setup was developed that enables measurements of effective multicomponent gas diffusion coefficients. Gas concentrations are detected using infrared light spectroscopy, which eliminates the necessity of gas sampling. To test the accuracy of the apparatus, binary diffusion coefficients were determined using different gases and at multiple pressures and temperatures. Effective diffusion coefficients were then determined for different rock types. Experiments were performed multiple times for quality control and to test reproducibility. The measured binary diffusion coefficients without porous media show a very good agreement with the published literature data and available correlations based on the kinetic gas theory (Chapman-Enskog, Fuller-Schettler-Giddings). Measurements of effective diffusion coefficients were performed for three different rock types that represent various facies in a UHS project in Austria. A correlation between static rock properties and effective diffusion coefficients was established and used as input to improve the numerical model of the UHS. This input is crucial for the simulation of back-produced gas composition and properties which are essential parameters for storage economics. In addition, the results show the impact of pressure on effective diffusion coefficients which impacts UHS performance
Hosseinzadehsadati, Seyedbehzad (Technical University of Denmark) | Amour, Frédéric (Technical University of Denmark) | Hajiabadi, Mohammad Reza (Technical University of Denmark) | M. Nick, Hamidreza (Technical University of Denmark)
Abstract CO2 injection in depleted oil and gas reservoirs has become increasingly important as a means of mitigating greenhouse gas emissions. This study investigates coupled multiphysics simulations of CO2 injection in chalk reservoirs to better understand the complex thermo-hydro-mechanical-chemical (THMC) processes involved. Two compositional models are created: an isothermal model and a non-isothermal model. Since temperature impacts on fluid compositions have introduced errors in estimating the reservoir's compositions, we made certain simplifications on fluid compositions for the thermal model to address this issue. By using the simplified model, we simulate the temperature propagation of cold fluid into a hot reservoir to observe induced thermal stress due to temperature changes. Despite these simplifications for geomechanical modeling, the propagation of CO2 in the depleted gas reservoir was calculated without considering thermal effects, assuming that the density and viscosity of CO2 remained constant with temperature change in the coupled simulation. Our findings provide valuable insights into the THMC processes involved in CO2 injection in the depleted gas reservoir and highlight the importance of accurately modeling thermal effects to improve simulation accuracy.
Abstract Finite element simulations investigate the effect of cement sheath length and proximity to perforations, varying the spacing of these and their length. The motivation is to assess the well integrity risk in fracturing operations, typical in shale gas or tight sandstone stimulation operations. Other applications are de-risking of injection operations in CO2 or H2 storage. Simplified simulations highlight unwanted associated fracturing in hydraulic fracturing operations, or as additional consequences of unplanned fracturing occurring due to injectivity impairment. Several cases are simulated: 1. Cased, cemented and perforated horizontal well interval; 2. Open hole perforated horizontal well interval; 3. Vertical cased and cemented interval. Results show that under some circumstances, fracturing may be expected in the well's cement sheath. These are locations where simulations show a possible fracturing scenario which could lead to unwanted pressure communication. However, the simulations all agree that there is no induced fracturing at more distant cement sheath sections. The major risk shown here is fracture initiation close to the perforated interval, suggesting that propagation along the cement sheath, although possible, is less likely.
Abstract Due to the maturity of water-flooded oil reservoirs, as a consequence of heterogeneity, fluids move preferentially through the most permeable layers, leaving large volumes of mobile oil remain unswept. Injection of oil-in-water (O/W) dispersions can regulate the permeability contrast between these layers. Droplet size distribution and porous media heterogeneity are the principal features that characterize displacement front uniformity. The intent of this work is therefore to provide a fundamental insight into number of factors may influence the dispersion flow in porous media. The workflow in this study is comprised of three stages. First, O/W dispersions with low oil concentrations were prepared and characterized. Second, a series of O/W dispersion injection experiments was conducted. The objective of this stage was to evaluate the distribution of retained oil droplets, pressure drop and permeability reduction in different sandstone core-plugs. Finally, a mathematical model based on the experimental setup was developed to describe the dynamics of O/W dispersion flow. Finite element method (FEM) was employed to numerically solve the governing equations. The experimental results revealed that the number and size of retained oil droplets decay with the core depth and correspondingly in the effluent. Verification of the numerical model was performed by comparing the pressure drop and permeability reduction to the results of analytical solutions. The model showed good validation with the experimental data. The numerical results were closely match those of the analytical solutions. The current work presents a potentially efficient method of modelling to describe the dispersion flow in porous media. However, for field applications, further improvement to the model complexity is required.
Shaker Shiran, Behruz (NORCE Norwegian Research Centre AS) | Djurhuus, Ketil (NORCE Norwegian Research Centre AS) | Alagic, Edin (NORCE Norwegian Research Centre AS) | Lohne, Arild (NORCE Norwegian Research Centre AS) | Rolfsvåg, Trond Arne (Hydrophilic AS) | Syse, Harald (Hydrotell AS) | Riisøen, Solveig (Hydrotell AS)
Abstract As oil is produced from a reservoir, the free-water-level (FWL) rises. Monitoring the FWL during oil production is of high value for the operators. This knowledge can aid placement of new wells on the field, improve the production strategy on a well level and reduce the production of water. We propose a new method for continuously measuring in-situ water pressure in an oil reservoir and investigate, both experimentally and by simulations, how this information can be used in reservoir monitoring. Laboratory experiments with Berea sandstone and Mons chalk core samples were performed using mineral oil and synthetic brine in a test setup designed for this study. The pressure in the water phase is measured with hydrophilic probes at five locations on the core during drainage and imbibition processes. Data including temperatures, pressures, resistance, water production, and pump logs were continuously collected in a cloud solution for live monitoring during the experiments. The experimental results were interpreted using a numerical simulator (IORCoreSim) to identify key mechanisms behind probe response and upscaling to reservoir scale. A new setup with 5 internal pressure probes for measuring in-situ water pressure with higher oil pressure was successfully designed and tested. An advanced watering system to inject water to the probe tips was included in the test setup and can be operated automatically. Experimental results showed that the water-wet probes can measure low water pressure inside high pressure oil column. The change in water pressure during drainage of low permeable Mons core and medium permeability Berea core was continuously measured. The probes were able to measure water pressure in different sections of the core with change of water saturation in the core. After the drainage process, the water pressure at one side of the core was increased. The propagation of water pressure at low water saturations were then detected in the 5 probes along the core sample. This paper presents a revolutionary technique to measure pressure in a thin film of water with low mobility. Continuous monitoring of water pressure inside the hydrocarbon phase can be used to enhance the production on a well level and improve the strategy on a field level. This results in increased production, reduced operational costs and environmental impacts.
Samarkin, Yevgeniy (King Fahd University of Petroleum and Minerals) | Amao, Abduljamiu Olalekan (King Fahd University of Petroleum and Minerals) | Aljawad, Murtada Saleh (King Fahd University of Petroleum and Minerals) | Sølling, Theis Ivan (King Fahd University of Petroleum and Minerals) | AlTammar, Murtadha J. (Saudi Aramco) | Alruwaili, Khalid M. (Saudi Aramco)
Abstract Fractured carbonate formations composed of chalk and limestone rock lithologies develop several issues over time, reducing fractures’ conductivity. One such issue is the embedment of the proppant that happens due to the soft nature of the carbonate rocks. Reduction of fractures’ conductivity results in the need for refracturing operations that require pumping tremendous amounts of water. The refracturing operations can be avoided if the fractures are maintained conductive for a longer time. This research targets reducing the severity of proppant embedment issues in carbonate formations through rock hardening by diammonium hydrogen phosphate (DAP) treatment. The chalk and limestone rock samples were treated with a DAP solution of 0.8M concentration at three temperatures, namely 30°C (ambient), 50°C, and 80°C. The samples were treated by immersion in solution, in which rocks were kept reacting for 72 hours. The treated samples were analyzed using the SEM-EDX technique to identify new minerals and changes in the morphology of the rock samples. Moreover, the changes in the hardness of the samples were analyzed by the impulse hammering technique. In addition, the proppant embedment scenario was mimicked in the rocks by utilizing Brinell hardness measurements before and after their treatment. The SEM analysis demonstrated that the treatment of carbonate rocks with a DAP solution results in the formation of hydroxyapatite (HAP) minerals. In addition, it was observed that the temperature of the treatment affects the crystallization patterns of the HAP minerals. Further results demonstrated that DAP treatment at elevated temperatures significantly improves the hardness of the samples. Young’s modulus of the rock samples increased by up to 60 - 80% after the treatment. In addition, studies have shown the improvement of rocks’ resistance to indentations. The sizes of the dents created by the Brinell hardness device were smaller than before the treatment. Overall, it was demonstrated that the Brinell hardness of the rock samples improved by more than 100%. This research demonstrated that treating carbonate rocks with DAP solution results in their hardening and improved samples’ resistance to indentation. Moreover, the treatment of rock samples at temperatures similar to reservoir conditions even further improves the mechanical properties of the carbonate rocks. Upscaling laboratory DAP treatment techniques for reservoir applications will introduce new practical methods for maintaining the long-term conductivity of propped fractures. Such a procedure will help avoid refracturing operations, resulting in better and more sustainable management of water resources.
Abstract Injecting fluid into subsurface strata has the potential to cause earthquakes by altering pore pressure and subsurface stress. To assess the seismic hazard associated with subsurface flow processes, it is necessary to understand the underlying mechanics of fluid-induced fault reactivation. In this study, we conduct a coupled hydro-mechanical modeling of fluid injection to a strike-slip fault with rate-and-state friction. We account for the fluid flow across and along the fault, as well as the hydromechanical properties of faults in the normal and tangential directions. We model the injection-induced slip of a strike-slip fault, and the simulation results indicate that there are two primary factors that affect injection-induced seismicity. The first factor is that the initiation of rupture is directly related to the diffusion of pore pressure in the near field where there is high shear stress and a large reduction in fault strength due to the significant pressure change. The second factor is that the transfer of shear stress from the nucleation zone promotes the advancement of the slip front to the near- and far field. Our results are quite conservative since the model chose pf as the relevant pressure when calculating the effective normal stress and the shear stress has a slight effect on the pressure variation. Finally, the sensitivity analysis indicates that greater tangential permeability values delay the onset of fault rupture and diminish the likelihood of fault reactivation. Higher stiffness induces fault slip earlier but reduces its magnitude.
Abstract Hydraulic fracturing has long been an established well stimulation technique in the oil & gas industry, unlocking hydrocarbon reserves in tight and unconventional reservoirs. The two types of hydraulic fracturing are proppant fracturing and acid fracturing. Recently, a new of hydraulic fracturing is emerging which is delivering yet more enhanced production/injection results. This paper conducts a critical review of the emerging fracturing techniques using Thermochemical fluids. The main purpose of hydraulic fracturing is to break up the reservoir and create fractures enhancing the fluid flow from the reservoir matrix to the wellbore. This is historically achieved through either proppant fracturing or acid fracturing. In proppant fracturing, the reservoir is fractured through a mixture of water, chemicals and proppant (e.g. sand). The high-pressure water mixture breaks the reservoir, and the proppant particles enter in the fractures to keep it open and allow hydrocarbon flow to the wellbore. As for acid fracturing, the fractures are kept open through etching of the fracture face by acid such as Hydrochloric Acid (HCl). An emerging technique of hydraulic fracturing is through utilization of thermochemical solutions. These environmentally friendly and cost-efficient are not reactive as surface conditions, and only react in the reservoir at designated conditions through reservoir temperature or pH-controlled activation techniques. Upon reaction, the thermochemical solutions undergo an exothermic reaction generating in-situ foam/gases resulting in creating up to 20,000 psi in-situ pressure and temperature of up to 700 degrees Fahrenheit. Other reported advantages from thermochemical fracturing include the condensate bank removal (due to the exothermic reaction temperature) and capillary pressure reduction.
Abstract High-CO2 gas fields present a dilemma to Host Government wanting to both ensure security of supply and achieve net zero aspiration. While carbon capture and storage (CCS) technology holds promise of technical feasibility to unlock these fields, its commercial success ultimately hinges on the choice of an appropriate business model. This study compares the economics of the traditional business model i.e., CCS as part of the upstream petroleum operation dedicated to a Production Sharing Contract (PSC) vs. the alternative business model i.e., a regional CCS hub separately managed by a Special-Purpose Vehicle (SPV). To maximize the return on its investment in a gas value chain, Host Government aims to minimize the upstream cost of gas (COG), which in turn comprises the technical cost, fiscal/tax charge, and cost of capital components. Thus, in this paper, the business models are compared in terms of their COG, and the reasons for the differences are further analyzed by looking at the drivers affecting the components. To illustrate the comparison numerically, synthetic technical data based on several recent CCS projects are evaluated under Malaysian petroleum fiscal arrangement and tax regime. The scope of the CCS projects contemplated in this study is restricted to managing the CO2 inherent in upstream high-CO2 gas fields. The paper finds that the alternative business model outdoes the traditional in several ways. The economies of scale of a hub design optimize capital expenditure, while utilization by multiple users reduces hub operator’s risk, potentially lowering tariff. The SPV can better realize tax incentives and also benefit from a lower tax rate. In PSCs where cost recovery provisions prioritize operating expenditure over capital expenditure, upstream Contractors may prefer paying tariff per usage rather than building their own CCS facility up front. Access to cheaper financing from environmental, social, and governance (ESG) investors and government agencies, coupled with the perception of lower business risks, should also translate into a lower cost of capital. There are various spin-offs and qualitative benefits too. While the paper affirms the intuitive expectation that the alternative business model generally surpasses the traditional, it also cautions that the optimal choice may switch beyond certain thresholds (number of fields, distance between PSCs, volume of CO2, etc.). In addition to the between-model selection problem, the paper also discusses within-model fine tunings and optimization. This paper lays out important caveats and considerations that might be of interest to petroleum authority and government policymakers tasked with the development of business model for upstream CCS projects.