bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessment of Fishbone Well Design Performance in a Tight Carbonate Compared to Single Extra-Long MRC Lateral
Authors: Alyan Mohand , Al Sowaidi Alunood 
Published: September 2019

Abstract
A reservoir simulation study of different fishbone well designs performance compared to a base development well design of extra-long maximum reservoir contact (MRC) single lateral wells is presented. The objective is to compare different well design concepts in a waterflood recovery scheme to achieve production target rate and maximize resource value for economic development of an undeveloped tight carbonate reservoir. The studied reservoir is located in a giant offshore oil field in the Middle East and was used as a representation of the different tight reservoirs within the field. It is characterized by poor quality rocks with a permeability trending from 2 – 0.5 md in a SE – NW direction.
The study compromises an assessment of the achievable initial maximum oil rate, volumetric reservoir sweep and expected ultimate oil recovery factor for different well design concepts for a base short well spacing utilized for effective pressure support. In addition to that, the impact of fishbone well design on well count reduction potential utilizing twice the base short well spacing compared to single lateral wells development design utilizing the base short well spacing was evaluated.
A sector model with equal producer to injector ratio was used with refined gridding to wells and bulk area gridded with a cell size of 10 m by 10 m in a representative area of the reservoir. The modeled wells incorporated with vertical flow performance tables with gas lift capabilities. The analysis also incorporated generating streamlines for analyzing fishbone well designs areal reservoir sweep and an examination of remaining movable oil areal distribution. An assessment matrix was formulated for comparing extra-long MRC single laterals base development design versus different fishbone well designs. The assessment matrix incorporated in addition to reservoir related flow performance indicators: drilling complexity and well cost, well life cycle activities, etc. for a comprehensive assessment.
The main findings show that fishbone well designs have complicated areal sweep performance, especially with sealed motherbore, that result in a lower oil recovery factor with higher hydrocarbon pore volume injected and water oil ratio compared to extra-long MRC single laterals. Also, fishbone well designs have serious limitations during well life cycle activities compared to extra-long MRC single lateral design in terms of stimulation, well accessibility and well intervention options making the extra-long MRC single laterals the preferred field development concept within tight reservoirs especially with the base short well spacing. Finally, the analysis has shown that Fishbone well designs can’t reduce the well count since base short well spacing is still needed for effective pressure support by water injection in addition to maximizing the oil recovery factor within the field life time and building and sustaining the target plateau.
Visual Recognition of Drill Cuttings Lithologies Using Convolutional Neural Networks to Aid Reservoir Characterisation
Authors: Kathrada Muhammad , Adillah Benjamin Jacob 
Published: September 2019

Abstract
There are a vast number of reservoirs with drill cuttings and core images that have classification problems associated with them. This could be due to the images not being classified in the first place, or the images may be available but the interpretation reports could be missing. Another problem is that images from different wells could be interpreted by different wellsite geologists/sedimentologists and hence result in an inconsistent classification scheme. Finally, there could also be the problem of some images being incorrectly classified. Ergo it would be desirable to have an unbiased objective system that could overcome all of these issues. Step in convolutional neural networks. Advances during this decade in using convolutional neural networks for visual recognition of discriminately different objects means that now object recognition can be achieved to a significant extent. Once the network is trained on a representative set of lithological classes, then such a system just needs to be fed the raw drill cuttings or core images that it has not seen before and it will automatically assign a lithological class to each image and an associated probability of the image belonging to that class. In so doing, images below a certain probability threshold can be automatically flagged for further human investigation. The benefit of such a system would be to improve reservoir understanding by having all available images classified in a consistent manner hence keeping the characterization consistent as well. It would further help to reduce the time taken to get human expertise to complete the task, as well as the associated cost.
Improvement of the SAGD Process by Use of Steam-Foam: Design and Assessment of a Pilot Through Reservoir Simulation
Authors: Abdul Ghani Mohamad , Ayache Simon Victor , Batôt Guillaume , Gasser-Dorado Julien , Delamaide Eric 
Published: September 2019

Abstract
Although SAGD is a very popular in-situ extraction method in Canada, this thermal process relies on huge energy and water consumption to generate the steam. Irregular growth of the steam-chamber due to heterogeneities further degrades its yield. Contact between the steam chamber and the overburden also leads to heat losses. The objective of this paper is to investigate how Foam Assisted-SAGD could mitigate these technical issues and improve the efficiency of the SAGD process. Compositional thermal reservoir simulations are used to simulate and analyze a Foam Assisted-SAGD pilot. The shear-thinning effect close to the wells is also accounted for. The simulations are run on a homogeneous model mimicking the Foster Creek project in Alberta, Canada. Several type of injection sequences have been analyzed in terms of foam formation, back-produced surfactants and cumulative Steam-Oil-Ratio. Results are compared with the original SAGD performance. In order to propagate the foaming surfactants throughout the steam chamber the injection sequence needs to be properly determined. A simple continuous Foam Assisted-SAGD injection would lead to an accumulation of surfactant between the wells due to gravity segregation, preventing the foam from acting on the upper part of the steam chamber. Furthermore surfactant production occurs after a few weeks due to the proximity of the producer and the injector. A proper injection strategy of the type SAGD/slug/SAGD/slug is found to delay the chemical breakthrough and increase the amount of surfactant retained in the reservoir while allowing the surfactant propagation throughout the steam chamber. After optimization the Foam Assisted-SAGD process appears to be technically promising.
Oilfield Performance in the Presence of Asphaltene Using a Dynamic Flow Simulation
Authors: Al-Qasim Abdulaziz , AlAnazi Amer , Miftakhov Ruslan 
Published: September 2019

Abstract
This paper discusses a method for optimizing production and operation for onshore/offshore wells. Optimizing the production of oil and gas fields necessitates the use of accurate predication techniques to minimize uncertainties associated with day-to-day operational challenges related to serious operational problems caused by asphaltene deposition. It involves the use of a dynamic flow simulator for modeling oil and gas production systems and reservoir management to determine the feasibility of its economic development. Many studies have focused on relating asphaltene precipitation flocculation and deposition in oil reservoirs and flow assurance in the wellbores. Experimental techniques and theoretical models have been developed trying to understand and predict asphaltene behavior. Nevertheless, some ambiguities still remain with regard to the characterization asphaltene in crude oil and its stability during the primary, secondary, and tertiary recovery stages within the near-wellbore regions.
A synthetic onshore full-field scale that is based on a heterogeneous three-dimensional Cartesian single-well model is considered in this paper. Two wells (a producer and an injector) and one reservoirs are considered to evaluate the dynamic properties under the influence of asphaltene. The size of the reservoir is 25 ft × 25ft × 20 ft and is represented by grid numbers of 50 columns × 50 rows × 5 layers with 12 hydrocarbon components constituting the constant crude composition of this model. The model comprised a total of 12,500 grid blocks. The three-dimensional simulation employed 5-layers, incorporating all relevant production and reservoir data. Different production scenarios were investigated to define the most appropriate and efficient production strategy. This paper provides a method to assess the effect of asphaltene precipitation, flocculation, and deposition in the well productivity and the economic impacts related to it and investigating prevention techniques and other related in-situ pore level flow assurance parameters.
The results will include a comparison of production rates with and without asphaltene precipitation, flocculation, and deposition. In addition, it provides a comparison of asphaltene precipitation, flocculation, and deposition at different times using varying bottomhole and production rate constraints. Several cases (i.e., WAG cycles, completion, target layers of injection, etc.) are tested to help in selection of the optimum completion and operating strategy in the presences asphaltene. The paper will provide insight into factors affecting the flow assurance of oil and gas reservoirs.
Reconciliation of Production Data and Geology for Robust Development Plan
Authors: Goyal Praffula , Koeck Charles-Henri , Bensadok Abdelaziz , Lavenu Arthur P.C 
Published: September 2019

Abstract
This paper discusses the re-construction of the long-term development plan for an offshore giantfield located in Abu Dhabi with the aim to mitigate the rising challenges in the maturing field. The primary objective is to understand the reservoir behavior in terms of fluid movement incorporating the learning from the vast history while correlating with the geological features.
The field has been divided into segments based on multiple factors considering the static properties such as facies distribution, diagenesis, faults, and fractures while incorporating the dynamic behaviors including pressure trends and fluid movements.
On further analysis, various trends have been identified relating these static and dynamic behaviors. The production mechanism for each of the reservoirs and the subsequent sub reservoirs were analyzed with the help of Chan plots, Hall plots and Lorentz plots which distinctly revealed trends that further helped to classify the wells into different production categories.
Using the above methodology the field has been categorized in segments and color coded to indicate areas of different ranking. The green zone indicates area of best interest which currently has strong pressure support and wells can be planned immediately. The wells in this area are expected to produce with a low risk of water and gas. The yellow zone indicates areas of caution where special wells including smart wells maybe required to sustain production. This area showed relatively lower pressure support owing the location of the water injectors and the degraded facies quality between the injectors and the producers. The red zone highlights areas which are relatively mature compared to the neighboring zones and will require new development philosophy to improve the recovery. The findings from this study were used as the basis for a reservoir simulation study using a history matched model, to plan future activities and improve the field recovery.
This study involved an in-depth analysis incorporating the latest findings with respect to the static and dynamic properties of the reservoir. This has helped to classify the reservoir based on the development needs and will play a critical role in designing the future strategies in less time.
Drainage Strategy Optimization - Making Better Decisions Under Uncertainty
Authors: Sætrom Jon , Wojnar Konrad , Stunell Martha 
Published: September 2019

Abstract
Improved reservoir knowledge is key to extracting additional value from existing oil and gas assets. However, given the uncertainty in the subsurface, it is always a question if our current development strategy is the most robust choice, or if there are alternatives that can further increase the value of our field. This paper presents a novel solution that enables the asset team to answer these questions in a new way. Furthermore, the solution helps teams quickly identify and screen new opportunities that ultimately increase both subsurface understanding and the value of the field. The solution combines a quasi- Newton gradient based numerical optimization scheme with a stochastic simplex approximate gradient (StoSAG) algorithm. Because the algorithm is non-intrusive with respect to the fluid flow simulator, we can directly apply the solution on any flow optimization problem without the need to access the simulator source code. The solution is implemented using a microservice architecture that allows for efficient scaling and deployment either on cloud-based or internal systems. We demonstrate the proposed solution on a field containing 11 oil producers and 7 water injectors by optimizing the water injection and oil production rates. The machine learning algorithm allows us to quickly explore different drainage strategies, given the current understanding and associated uncertainties of the reservoir.
Specifically, the software solution suggests that 6 of the 18 pre-defined well targets are high risk and/or of little value. Running a second development scenario where we do not drill these six wells reduces the investment cost of this field by 163 MUSD and increases the expected net present value per well of the field by 48 percent. Compared with the reactive control drainage strategy approach, we increase the expected net present value of the field by 9.0 %, while simultaneously lowering the associated risk.
Simulation of Enhanced Oil Recovery in Pre-Salt Reservoirs: The Effect of High CO2 Content on Low Salinity Water Alternating Gas Injection
Authors: Carvalhal Arley Souza , Nunes Costa Gloria Meyberg , Vieira de Melo Silvio Alexandre 
Published: September 2019

Abstract
The high CO2 content of Brazil’s pre-salt fields, which may reach values from 20% to 44% molar, presents both a challenge as well as an opportunity. CO2 stripped from the produced gas cannot be released into the atmosphere due to environmental restrictions. Therefore, the whole amount of CO2 produced should be continuously reinjected into the reservoir. This work investigates the effect of CO2 content on the low salinity water alternating CO2 injection technique (CO2LSWAG) using a commercial compositional reservoir simulator. In these field-scale simulations, CO2 is stripped from the produced gas and reinjected into the reservoir. Primary oil recovery methods such as CO2 flooding and LSW flooding are also simulated. Chemical reactions between CO2 and the minerals present in the reservoir are modeled. Wettability change is assumed to be the main mechanism for improved oil recovery due to low salinity water injection. Compositional simulations of CO2 injection usually assume a constant injected gas rate. In this case, CO2 is supposed to come from an external source. In many petroleum reservoirs this assumption is true. Three factors are assessed in the present work. The first one is the natural reservoir pressure, which is the main driving force in primary production. The second factor is the amount of CO2 available for injection. The third one is the wettability change promoted by the reaction involving CO2. It is shown that in primary production, higher CO2 content leads to quicker depletion of the natural energy of the reservoir, leading to lower oil recovery. Nevertheless, higher CO2 content also means that more gas is available for reinjection, potentially leading to increased oil production. Finally, as CO2 reacts with minerals it promotes a change in wettability from an oil-wet to a water-wet state. It is shown that the CO2 content is an important variable to be assessed in a high CO2 content reservoir. Optimal injection practices must take these three aspects into consideration.
Petro-Elastic Modeling Applied to Multi-Porosity/Multi-Permeability Cores through a Simulation to Seismic Method
Authors: Ramsay Travis , Prabhakar Aravind 
Published: September 2019

Abstract
Multi-rock type cores can be characterized by complex higher order connectivity relationships within an agglomerated petrophysical system. A solution that relates multiphase flow simulation in cores to time-lapse seismic properties in order to examine closed-loop 4D integration is performed at a high level on a plug. While a 4D workflow is not explicitly examined in this work, the requisite petro-elastic modeling (PEM) method based on a simulation-driven interpretation of the Gassmann equation is described and a comparison is made with its empirically derived counterpart. This work illustrates that a simulation-driven petro-elastic modeling approach can be used to generate time-dependent saturated rock properties consistent with seismic attribute description at the plug and core scales. The results demonstrate the simulation-driven approach, of a petro-elastic model embedded in a reservoir simulator, as an alternative to relating pressure and saturation from reservoir simulator-to-seismic-derived properties using a priori empirically based correlations. The method discussed in this paper maintains appreciable continuity with the results of empirically based petro-elastic methods but demonstrates differences commensurate with principal fluid differentiation capability inherent to reservoir simulator-derived data and observed time-lapse seismic response. The significance of applied multi-porosity relationships is further realized upon examination of the time-dependent petro-elastic model results.
Numerical Relative Permeability Upscaling Based on Digital Rock Analysis
Authors: Sun Qian , Zhang Na , Alyafei Nayef , Wang Yuhe , Fadlelmula Mohamed 
Published: September 2019

Abstract
Reservoir simulation is commonly performed on upscaled models of complex geological models. The upscaling process introduces a principal challenge in accurately simulating two-phase fluid dynamics in porous media. To tackle this challenge, it is important to upscale relative permeability accurately. In this paper, a numerical method, which is based on the mimetic finite difference method (MFD) and digital rock analysis (DRA), is proposed for relative permeability upscaling. The validation of MFD is tested by two different cases with exact pressure solution. Then, the relative permeability of the digital rock (small element) is calculated based on the pore network modeling. The small elements are combined together to make up a larger model with different sizes (4×4×4, 6×6×6, 8×8×8, 10×10×10 elements). Finally, the accuracy of the proposed method is verified by comparing simulated results of the different sizes with that of the original one. The results show that MFD can solve the multi-phase flow scenarios with high accuracy and the L2 error follows the opposite trend to that of mesh size, which means that more refinement level gives less L2 error. For the upscaling of absolute permeability, the relative error can be decreased to 2.27%, which confirms that the proposed method is capable of calculating the absolute permeability with higher refinement levels. The fitting degree of the simulated water phase relative permeability to the original one is better than that of oil phase. The average relative error of water pahse relative permeability upscaling can decrease to less than 5.0%. It is found that the results will get worse when the model includes less elements. Especially at low water saturation, there exists some fluctuations for relative permeability curves and it may be due to the unstable state of the waterflood front with less elements involved.
Steady-State Multi-Phase Relative Permeability Under Simultaneous Water and Gas Injection: Application on Different Rock Types
Authors: Moghadasi Leili , Renna Dario , Bartosek Martin , Maddinelli Giuseppe 
Published: September 2019

Abstract
Quantification of multi-phase flow processes taking place in natural porous and fractured rocks has a remarkable relevance to economically sustainable management and viable development of oil- and gas-bearing geologic formations. Simultaneous flow of two- and three- fluid phases in porous media is typically based on a continuum scale description which imbues relative permeabilities as key system parameters to be estimated and linked to fluid saturations. Estimates of relative permeabilities are then employed to support better the quantification of productivity, injectivity, and ultimate recovery from reservoirs. In this work, we report the results of laboratory-scale three-phase relative permeabilities on diverse core samples. We also investigate the saturation history dependency (i.e. hysteresis) of three-phase relative permeability during under simultaneous water and gas injection.
Three-phase relative permeability data are obtained at different condition by the way of a Steady-State (SS) technique. We use direct X-Ray technique to assess the spatial and temporal dynamics of in-situ saturations. Dual X-Ray energies are employed to assess the SS three-phase saturations. The use of in-situ X-Ray scanning technology enables us to accurately measure fluid displacement during the core-flooding test. The SS three-phase experiments are condcuted by following various saturation paths including CDI, DDI and IDI. The C, D and I letters represent as Constant, Increasing and Decreasing (i.e., CDI saturation variation abbreviates Constant water, Decreasing oil and Increasing Gas).
We observe in all the of the tests, water relative permeabilities display an approximately linear dependence on the logarithm of its own saturation and show no dependency upon saturation history.
Three-phase oil relative permeability appears to be varied with all saturations and be dependent on all saturations phases. Gas three-phase relative permeability was affected more by saturation history than other phases. However in the test where the gas fractional flow was increased, the dependency of gas relative permeability on gas saturation was observed.
As only a limited quantity of complete three-phase data are available, this study stands as a reliable reference for further model development and testing.