bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of CCUS for Improved Oil Recovery on CaCO3 Scaling Potential of Produced Fluids
Authors: Ness Giulia , Sorbie Ken Stuart , Al Mesmari Ali Hassan , Masalmeh Shehadeh 
Published: June 2022

Abstract
Unlike other CCUS technologies, CO2 EOR has been widely implemented at a commercial level and on an industrial scale. In CO2 EOR, CO2 can be injected on its own or alternated with water in CO2 WAG (water-alternating-gas). Both applications have a direct impact on produced fluid compositions influencing GOR, water cut, CO2 concentration and consequently Ca2+, alkalinity and pH. The variation of fluid compositions has an inevitable impact on the scaling potential of produced fluids and on the resulting level of scale formation and its mitigation strategy.
The aim of this work is to investigate the scaling potential changes for a wide range of CO2 WAG scenarios in a high salinity carbonate reservoir in the Middle East using input data from reservoir modelling simulations and running multiple sensitivity studies. The main scale formed in this reservoir is calcium carbonate (CaCO3).
The equilibrium reservoir water, the produced water chemistry profiles from downhole to stock tank and the scaling risk profiles are modelled using a commercial integrated PVT and aqueous phase software. A rigorous scale prediction procedure previously published by the authors is applied to accurately calculate scale risk trends for variable production scenarios.
As CO2 increases in the WAG cycle, reservoir pH drops but the equilibrium with CaCO3 rock causes an increase in alkalinity. This results in more CaCO3 precipitation in the production system where pressure drops and CO2 flashes off solution. Hence, these results show unequivocal detrimental impact of CO2 WAG on the calcium carbonate scaling potential of produced fluids. This leads to a need for operational and/or chemical adjustments to the scale management program when this technology is deployed.
Whilst in this field some CaCO3 scale is predicted to form downhole, but this is not a severe problem although it may need to be addressed. The separator is operated at a sufficiently high pressure that calcium carbonate is not expected to form there. Changing operating pressures and CO2 and H2S concentrations can shift some of the problem to the separator, but if this remains at high pressure there will be no scale precipitation here. However, the calcium carbonate scale will predominantly precipitate at stock tank conditions.
Implementing green technologies such CCUS is fundamental to achieving net zero goals and this work clearly shows that actions need to be taken to manage the associated CaCO3 scale problems in the produced fluids to make this application successful.
Model-Based Life-Cycle Optimization for Field Development and Management Integrated with Production Facilities
Authors: Schiozer Denis J. , Santos Susana M. , Santos Antonio Alberto S. , von Hohendorff Filho João C. 
Published: June 2022

Abstract
Reservoir simulation models often support decision making in the development and management of petroleum fields. The process is complex, sometimes treated subjectively, and many methods and parameterization techniques are available. When added to uncertainties, the lack of standardized procedures may yield largely suboptimal decisions. In this work, we present a comprehensive outline for model-based life-cycle production optimization problems, establishing guidelines to make the process less subjective. Based on several applications and a literature review, we established a consistent methodology by defining seven elements of the process: (1) the degree of fidelity of reservoir models; (2) objective function (single- or multi-objective, nominal or probabilistic); (3) integration between reservoir and production facilities (boundary conditions, IPM); (4) parametrization (design, control and revitalization optimization variables); (5) monitoring variables (for search space reduction); (6) optimization method, including optimizer/algorithm, search space exploration, faster-objective function estimators (coarse models, emulators, others), type of ensemble-based optimization (robust or nominal based on representative models); (7) additional improvements (value of information and flexibility). With an application on a publicly available benchmark reservoir, this work shows how a model-based life-cycle optimization process can be systematically defined. In this initial work, the focus is the field development phase and some simplifications were made due to the high computational demand, but in future works we plan to address the control and revitalization variables and reduce the number of simplifications to compare. The optimization results are analyzed to understand the evolution of the objective function and the evolution of the optimization variables. We also discuss the importance of including uncertainties in the process and we discuss future work to emphasize the difference between life-cycle (control rules) and short-term (effective control) management of equipment, as well as ways to deal with the computational intensity of the problem, such as the combined use of representative models and fast simulation models.
Oil Recovery by Low-Rate Waterflooding in Water-Wet Sandstone Cores
Authors: Aslanidis Panagiotis , Strand Skule , Puntervold Tina , Yeboah Kofi Kankam , Souayeh Iyad 
Published: June 2022

Abstract
Smart Water or low salinity water injection are environmentally friendly methods for efficient hydrocarbon recovery. Wettability alteration towards more water-wet conditions and generation of positive capillary forces and spontaneous imbibition are responsible for the increased oil production. Spontaneous imbibition to expel oil from the low permeable matrix is a time-dependent process and both injection rate and oil viscosity are important factors affecting the contribution of capillary and viscous forces to the oil production.
It is hypothesized that when capillary forces and spontaneous imbibition are important for oil production, low flooding rate must be applied in laboratory corefloods to allow for wettability alteration. In this study the effect of flooding rate on oil displacement from low permeable sandstone cores has been examined. Viscous forces have been varied by injection at two different rates and performing spontaneous imbibition experiments, in addition to varying the oil viscosity. Low permeable, water-wet Bandera Brown outcrop sandstone cores were used as the porous medium, and synthetic oil and formation water were used to avoid any wettability alteration during fluid restoration and oil displacement.
The results showed only small differences in oil recovery by spontaneous imbibition and viscous flooding at high and low rate, proving that capillary forces and spontaneous imbibition were major contributors to the oil mobilization and production process. By varying the oil viscosity, the results indicated that capillary forces were especially important for oil displacement at higher oil viscosity, since the ultimate oil recovered by low-rate injection was higher than that from high-rate injection. As expected, capillary number calculations indicated that capillary forces were important for efficient oil displacement from the low permeable, water-wet cores used in this study. However, there was no direct link observed between generated pressure drops at high and low injection rate, including spontaneous imbibition, and the ultimate oil recovery. Thus, to simulate oil production in the middle of the reservoir it was concluded that low rate waterflooding is needed in laboratory tests to allow spontaneous imbibition into the matrix to displace oil by positive capillary forces.
The combination of using oils that differ in viscosity in different injection rates could add some additional information in the literature on how to increase the efficiency of waterflooding by a low injection rate.
Viscosity from Geochemical Techniques: A Case Study for a Heavy Oil Field on the UKCS
Authors: Cutler Ian , Cely Alexandra , Moore Julian , Yang Tao , Birch Nicholas , Ablard Peter 
Published: June 2022

Abstract
Heavy oil fields are characterised by complex chemistries and exhibit a wide range of physical properties (especially oil viscosity). This paper describes the development of two innovative and cost-effective data acquisition methods: the optimised use of mud gas data and the geochemical characterisation of cuttings extracts, both as an alternative data source for oil viscosity determination. Applications of these methods can lead to the cost reduction of data acquisition programs and potentially improvements in oil recovery.
The mud gas provides real-time surface logging data. Due to the nature of heavy oil in the case study wells, the mud gas compositions contain mainly C1-C3. By comparing with the reservoir oil samples from the exploration and appraisal wells, we investigated the possibility of using mud gas while drilling to identify if the reservoir oil belongs to the high viscosity or medium viscosity group. For cutting analysis, we thoroughly investigated solvent extracts from cuttings from the exploration and appraisal wells and correlated them with the oil viscosity from the corresponding PVT samples. When such a correlation is established, we can then apply the correlation to predict oil viscosity from the cuttings of new production wells.
We achieved excellent results for both real-time oil viscosity identification from mud gas data and post well oil viscosity prediction from the extraction of cuttings. The C1/(C2+C3) is the key parameter for oil viscosity identification from the standard mud gas data in the field. For the past wells, the mud gas interpretation has high accuracy for determining if the reservoir oil belongs to the high viscosity or medium viscosity regions. We established a strong correlation between the biomarkers and the oil viscosity from the exploration and appraisal wells. When we applied the correlation to new production wells, the oil viscosity prediction was very close to the viscosity measurement from the wellhead PVT samples.
The geochemical techniques provide oil viscosity for critical decisions regarding well placement and reservoir management modelling. The new source of reservoir fluid data from mud gas and cuttings provides real-time fluid interpretation while drilling and close to PVT sample quality oil viscosity prediction after drilling. This new approach is cost-efficient and has a large potential to replace the downhole fluid sampling or expensive downhole logging tools for production wells.
Construction of Single-Porosity and Single-Permeability Models as Low-Fidelity Alternative to Represent Fractured Carbonate Reservoirs Subject to WAG-CO2 Injection Under Uncertainty
Authors: Menezes Davi Eber Sanches de , Santos Susana Margarida da Graça , Santos Antonio Alberto de Souza dos , Hohendorff Filho João Carlos von , Schiozer Denis José 
Published: June 2022

Abstract
Fractured carbonate reservoirs are typically modeled in a system of dual-porosity and dual-permeability (DP/DP), where fractures, vugs, karsts and rock matrix are represented in different domains. The DP/DP modeling allows for a more accurate reservoir description but implies a higher computational cost than the single-porosity and single-permeability (SP/SP) approach. The time may be a limitation for cases that require many simulations, such as production optimization under uncertainty. This computational cost is more challenging when we couple DPDP models with compositional fluid models, such as in the case of fractured light-oil reservoirs where the production strategy accounts for water-alternating-gas (WAG) injection. In this context, low fidelity models (LFM) can be an interesting alternative for initial studies. This work shows the potential of compositional single-porosity and single-permeability models based on pseudo-properties (SP/SP-P) as LFM applied to a fractured benchmark carbonate reservoir, subject to WAG-CO2 injection and gas recycle. Two workflows are proposed to assist the construction of SP-P models for studies based on (i) nominal approach and (ii) probabilistic approach of reservoir properties. Both workflows begin with a parametrization step, in which the pseudo-properties are optimized for a base case in order to minimize the mismatch between forecasts of the SP/SP-P and DP/DP models. The new parametrization methods proposed in this work showed to be viable for the construction of the SP/SP-P models. For studies under uncertainties, the workflow proposes obtaining pseudo-properties by robust optimizations based on representative models from a DP/DP ensemble, which proved to be an effective method. The case study is the benchmark UNISIM-II-D-CO with an ensemble of 197 DP/DP models and two different production strategies. The risk curves for production, injection and economic indicators obtained from DP/DP and SP/SP-P ensembles showed good match and the computational time spent on simulations of the SP/SP-P ensemble was 81% faster than DP/DP models, on average. Finally, the responses obtained from both ensembles were validated in a reference model (UNISIM-II-R) that represents the true response and is not part of the ensemble. The results indicate the SP/SP-P modeling as a good LFM for preliminary assessments of highly time-consuming studies. Besides, the workflows proposed in this work can be very useful for assisting the construction of SP/SP-P models for different case studies. However, we recommend the use of the high-fidelity models to support the final decision.
Simulation Evaluation of CO2-ECBM Potential in Karaganda Coal Basin in Kazakhstan
Authors: Serikov Galymzhan , Wang Lei , Asif Mohammad , Hazlett Randy 
Published: June 2022

Abstract
Karaganda Coal Basin is the largest coal basin in Kazakhstan with around one trillion cubic meters of coalbed methane, which has not been tapped to date. Also, simulation research on the production of coalbed methane from the Karaganda Coal Basin has not been conducted. Seeing that primary production of coalbed methane (CBM) is generally slow and recovery is not high, we proposed to evaluate the potential of implementing CO2-ECBM processes in Karaganda Coal Basin in Kazakhstan. It is known that CO2 adsorption on coal is much higher than methane so it is important to study the displacement mechanisms by CO2 injection. Using the geological parameters collected for Karaganda Coal Basin, main factors affecting methane production including different rates of CO2 injection and different starting times of CO2 injection were simulated and compared. CO2 injection into CBM reservoir is predicted to be effective due to competitive adsorption of these gases. This study provides a workflow model for evaluating and predicting efficient CBM production from the Karaganda Coal Basin. Results from simulation studies showed that injection of 110,000 m3/day of CO2 is as practical as injection of 150,000 m3/day, with small difference in recovery factor. The methane production enhances from 68.32% to 73.67-74.62% at injection pressure 15,000 kPa. The CO2 injection after 30% of primary recovery is the most efficient option. Early injection results in early breakthrough and high CO2 content in the producer well, while late injection leads to relatively low incremental recovery factor.
What Have We Learn from the Most Prolific Pad of Shale Gas in the Sichuan Basin?
Authors: Wang Meng , Che Mingguang , Jiang Yun , He Chunming , Weng Dingwei , Zhu Guangyou 
Published: June 2022

Abstract
There are more than 1300 horizontal wells in the Sichuan Basin shale reservoirsthat produce more than 20 billion cubic meters of gas in 2021. A test production of best-performing shale gas pad,so far in China, consisting of 8 horizontal wells, is over 4.7 × 106 m³/d (167.7 MMcf/d). The average EUR per well is estimated to exceed 2.0 × 108 m³(7.0 bcf).The underlying geological controlling factors including TOC content, porosity, gas saturation and brittle mineral content for these prolific wells were analyzed. The length of the well laterals drilling into the sweetest pay zone was characterized by well logging. The strategies of optimizing drilling and completion strategies used in these wells are discussed. In addition, the solutions to deal with the frequent occurrence of casing deformation are also proposed and adopted. Rate transient analysis was performed on these wells to assess the stimulation efficiency, which was further compared with those wells treated by conventional stimulationstrategies. It was found that the thickness and length of the completion in the highest quality pay zone are the two main geological controlling factors for the prolific wells. Different from the conventional stimulation strategies, the eight wells in one pad were all treated using higher intensity stimulation strategies. The average spacing between treated stages ranges from 85 m to 91 m, with tighter cluster spacing. Fracturing was temporarily plugged to passively treat sever deformation in two laterals consisting of 29 stages (total length of 2068m). Compared with the neighboring offset wells, the average bulk linear flow parameter of these eight well is 72% higher. Integration of geological designs (like sweet spot optimization) and engineering designs (such as tighter cluster spacing within longer stages, temporarily plugging fracturingand using more proppants), created a high-productivity template for the next stage of efficient developments of shale gas. The findings obtained in this study are also beneficial to unlock unconventional resources including shale oil and tight gas in China.
Designing CO2-EOR in Indonesia by Matching Business Strategy: Study Case East Java Field, Indonesia
Authors: Panggabean Yan Bastian , Pramadewi Tania Busran , Kusuma Erwin Andri , Maryanto Adam 
Published: June 2022

Abstract
JTB and SKW Field are proven fields which are hydrocarbon producing fields in Indonesia. JTB Field which is part of the Cepu Block is a proven field as well as the SKW Field which belongs to Pertamina EP Block. These two fields are 40 km apart and are currently a stranded field due to different operators. The JTB field is an early development field with CO2 characteristics &gt; 35%, while the SKW field is a mature field with oil producers. The SKW field has been produced for more than 30 years so it is a mature field with a fairly high decline rate.
Feasibility Study conducted to these project to know incremental value, especially value of engineering and carbon emission incentives from this project. After the formation of integration in the existing fields, where these two fields are under 1 Region, so that the integration of these two fields becomes possible. This integration is necessary considering that currently the JTB Field will be onstream in 2022, while on the one hand the SKW Field has started studies related to CO2 EOR. The pilot project that will be implemented is expected to be a pilot and proof of CO2 EOR which is a very new technology in the oil and gas industry in Indonesia.
Carbon emissions for around that can be saved with this method become integrated value engineering that provides value creation. For implementation on pilot phase, capital expenditure about USD 75 millions with additional carbon value around USD 30 millions. This paper will use a Value engineering approach combined with environmental analysis to see the value and incremental value for these two fields. Feasibility Study of this integrated project will be used for searching another financing and get evaluated by project sanctions
Deliverable for this feasibility study to calculate incremental return and amount of carbon emission value for this integrated project.
Estimation of the Half-Length of Non-Simultaneous-Closed Fracture Through Pressure Transient Analysis: Model and Case Study
Authors: Wang Zhipeng , Ning Zhengfu , Jia Zejiang , Cheng Qidi , Zhang Yuanxin , Guo Wenting , Zhu Qingyuan 
Published: June 2022

Abstract
During water-flooding development, severe water breakthrough has been observed in fractured wells. It is essential that determine the reason for water-breakthrough to improve the performance of production wells. However, the conventional pressure-transient analysis model hardly characterizes fracture-induced pressure response and fracture half-length, leading to erroneous results. This paper aimed at present an approach to estimate the half-length of non-simultaneous fracture induced in a relatively economical way. The non-simultaneous fracture closure flow (NFCF) model was proposed to characterize flow in induced fracture. To better characterize pressure response in induced fracture, we first modeled fluid flow in fracture with variable conductivity by two-part, variable-conductivity-linear flow and low-conductivity-linear flow. At the same time, fracture closure was considered to occur twice according to the pressure response of water injection wells, and its condiction followed experimental results. As a result, a semi-analytical solution was developed. We compared it with the finite-conductivity model to certify the accuracy. A new flow regime (the non-simultaneous fracture close linear flow) was discovered and behaved as two peaks on the pressure derivative curve. It will shorten the half-length of induced fracture if the new flow regime is ignored. Case studies showed that the NFCF model matched well with field data, which validated the practicability of the proposed approach. Our results might help accurately understand the reason for the water breakthrough - enormous the half-length of induced fracture was ignored in the past. In addition, the results also have provided significant insight for the operators could make reasonable decisions, reasonable well spacing and water-flooding rate, to improve production and water injection wells performance.