bluuebunny/crossref_metadata_2025_split huggingface dataset:
ANALISIS RISIKO PRODUKSI USAHATANI PADI DI PESISIR DANAU TEMPE
Authors: Mita Ros , Darma Rahim , Rahmadani Rahmadani , Salam Muslim , Amrullah A. 
Published: July 2020

Production risk is an occurrence of uncertainty in the agriculture sector and potentially potential loss and as a deviation from the agricultural production result obtained with the expected. This study aims to (1) To know the risk farming production at the shore of Lake Tempe in Mallusesalo Village, Sabbangparu District, Wajo Regency; and (2) To identify the efforts that need to be made by farmers in mitigating the risk of production of Lake Tempe coastal rice farming in Mallusesalo Village, Sabbangparu District, Wajo Regency. Data analysis techniques used are farm income analysis, coefficient of variation (CV) analysis, and descriptive analysis. The results of this study show that the average income of farmers is in Mallusesalo village of Rp. 17,243,261 / ha per season. Production risk obtained coefficient of variation (CV) of 0.046 can be interpreted as rice farming in Mallusesalo village has a low production risk. Efforts that need to be done by farmers in mitigating production risk are farmers observing weather conditions by referring to the planting calendar by taking into account the time of planting based on climate conditions. If there are signs of pest and disease attacks, farmers should prepare medicines (pesticides) accordingly. In addition, farmers can choose superior rice seed varieties, and farmers can also carry out biological biological control by utilizing natural enemies to reduce pest population.Keyword : Production; Risk; Mitigate; Rice; Lake Tempe
Evaluation of the Effectiveness of Continuous Gas Displacement for EOR in Hydraulically Fractured Shale Reservoirs
Authors: Moridis George , Reagan Matthew 
Published: July 2020

Abstract
The main objective of this study is to analyze and describe quantitatively the effectiveness of continuous gas displacement as an EOR process to increase production from multi-fractured shale oil reservoirs. The study uses CH4 continuously injected through horizontal wells parallel to the production wells as the displacement agent, and investigates the effects of various attributes of the matrix and of the induced and natural fracture systems.
This numerical simulation study focuses on the analysis of the 3D minimum repeatable element (stencil/domain) that can describe a hydraulically-fractured shale reservoir under production. The stencil is discretized using a very fine (mm-scale) grid. We compare the solutions to a reference case that involves simple depressurization-induced production (i.e., without a gas drive). We monitor continuously (a) the rate and composition of the production stream and (b) the spatial distributions of pressure, temperature, phase saturations, and relative permeabilities.
The results of the study indicate that a continuous CH4-based displacement does not appear to be an effective EOR method for hydraulically fractured reservoirs. In the absence of a natural fracture network or a Stimulated Reservoir Volume (SRV), continuous CH4 injection in a system with typical Bakken or Eagle Ford matrix and fracture attributes causes a reduction in water production and an (expected) increase in gas production, but does not lead to any significant increase in oil production. This is attributed to the injected gas dissolution into the oil and its early arrival at the hydraulic fracture, thus short-circuiting the EOR process by bypassing the bulk of the matrix. The effectiveness of the CH4-based gas drive is enhanced in the presence of a natural or induced fracture network because of deeper penetration into the matrix, but the increase in production is minimal.
The evaluation of a continuous CH4 gas drive provides important information for the management of EOR processes in shale oil reservoirs, including support for the exclusion of specific EOR strategies. Novel components of this study are the simultaneous consideration of all processes (flow, thermal, physical-chemical) associated with gas-drive EOR operations and production of fluids from shale oil reservoirs using high-resolution 3D grids, capturing in detail phenomena that are attenuated in coarser grids.
Enhancing the Recovery of an Extra Heavy Oil Reservoir by Using Low Salinity Polymer Flooding
Authors: Hernández Edgar , Valero Emil , Rodríguez Inti , Guerra Elio , Espinoza Javier , Briceño Rigoberto , Veliz Alida 
Published: July 2020

Abstract
This paper presents the design of a polymer flooding pilot test for an extra heavy oil reservoir located in the Orinoco Oil Belt, Venezuela. We describe a workflow consisting of extensive experimental work, numerical simulation and upscaling that led to an optimized polymer flooding. Experimental results show both oil recovery and polymer consumption can be further improved when using low salinity water for polymer mixing. In addition to this, the design of the pilot project forecasts the economic viability of the process.
We studied the impact of salinity in polymer rheology and oil recovery. Recovery factors were measured in core-flooding experiments performed using live extra heavy oil (API 8.7, Rs of 95 scf/bbl and viscosity of 2 000 cP at reservoir conditions) with high content of basic and acidic compounds (6.27 and 2.3 mg potassium hydroxide/g of oil, respectively). Rheology data showed that 50% less polymer is required to achieve the desired mobility ratio when polymer solution was prepared using low salinity water. Polymer flooding with a salinity of 1000 ppm resulted in a residual oil saturation (Sor) of 25%. This was further reduced to 17.4% when low-salinity polymer flooding was implemented. Numerical simulation of the pilot area indicated that using the optimal injection rate of 4 000 BWPD per well and a polymer solution-oil mobility ratio of approximately 10, lead to an optimum and attractive technical-economical injection scheme when using horizontal injector and producer wells pattern.
We attribute the incremental oil recovery to wettability alterations and ion exchange taking place between low salinity polymer flooding and the rock surface. The basic and acidic components of the crude oil of the Orinoco Oil Belt have a tendency to wet reservoir rocks when clays are present. We believe these compounds are detached from the rock during low salinity floods altering wettability into a more water-wet condition, therefore reducing Sor.
Low salinity polymer flooding is an attractive choice for EOR in heavy and extra-heavy oil reservoirs additional to thermal methods. The lower polymer requirements and the higher incremental recovery achieved by low salinity polymer flooding improves economic performance making its application attractive in reservoirs where primary recovery is normally below 10% of OOIP.
Optimization of Recovery by Huff and Puff Gas Injection in Shale Oil Reservoirs Using the Climbing Swarm Derivative Free Algorithm
Authors: Olusola Bukola Korede , Orozco Daniel , Aguilera Roberto 
Published: July 2020

Abstract
Recent improved and enhanced oil recovery (IOR and EOR) methods in shale reservoirs use huff and puff gas injection (H&P). Investigating the technical and economic impact of this technology for one well is challenging and time consuming. Even more so when the petroleum company is planning H&P and refracturing (RF) jobs in multiple wells. Thus, in this paper we present an original methodology to learn how to perform these tasks faster and at lower cost to improve oil recovery.
The procedure is explained with the use of an actual H&P gas injection pilot horizontal well in the Eagle Ford shale whose performance is matched using the methodology developed in this paper. The methodology includes use of an original Climbing Swarm (CS) derivative-free algorithm that drives, without human intervention, computer or laptop material balance (MatBal) and net present value (NPV) calculations. The code was written in Python. Following history match, the methodology demonstrates that significant improvements in oil recovery can be obtained by injecting gas at larger rates during shorter periods of time (as opposed to injecting gas at smaller rates during longer periods of time).
Once oil recovery improvement in a pilot horizontal well is demonstrated, the methodology is extended to the analysis of H&P gas injection and refracturing in horizontal wells and shale reservoirs that have not yet been developed or are in initial stages of development; this provides a preliminary assessment of H&P and refracturing potential.
Results indicate that oil recovery and NPV from multiple wells can be improved significantly by a strategic combination of H&P gas injection and refracturing. Combination of derivative-free optimization algorithms, MatBal calculations and net present value permits optimizing when to start the H&P gas injection project, the optimum gas injection rates and time-span of injection, reservoir pressure at which gas injection should be initiated in each cycle, and the time-span during which the well should produce oil, previous to starting a new cycle of gas injection. The development strategy of shale oil reservoirs could be improved significantly if the possibility of H&P gas injection is considered previous to field development. This could be the case of the Eagle Ford shale in Mexico, La Luna shale in Colombia and Venezuela, Vaca Muerta shale in Argentina and other shale oil reservoirs worldwide.
The paper contributes the development of an original methodology, which includes use of a derivative free algorithm we call "Climbing Swarm (CS)." CS drives the computer or laptop to perform MatBal and NPV calculations, without human intervention, once the optimization process is started. The methodology improves oil recovery and NPV from a single horizontal well or from multiple horizontal wells operating under H&P gas injection.
Assessment of Oil and Gas Resources in the Vaca Muerta Shale, Neuquén Basin, Argentina
Authors: Mayol Juan Cruz , Moridis Nefeli , McVay Duane A. , Lee W. John 
Published: July 2020

Abstract
According to the 2015 Energy Information Administration (EIA) global assessment (EIA 2015), Argentina ranks third among countries in shale-gas resources and fourth in shale-oil resources. The Vaca Muerta formation in the Neuquén basin holds most of these resources. After the first EIA assessment of these resources in 2011, there has been a huge increase in investment, given the interest of the Argentine government to recover the energy autonomy it lost in the 1990s. The objectives of this study were to update estimates of oil and gas reserves and resources with the four years of production data available, and to quantify the uncertainty in these estimates.
The Vaca Muerta formation was subdivided into sub-areas based on the fluid type. The most appropriate production decline model was determined for each sub-area and coupled with Markov-Chain-Monte-Carlo (MCMC) methodology to analyze and forecast production of existing wells to calculate reserves. The analyses of individual wells in each sub-area were used to create probabilistic type-decline curves. These curves were combined with the estimated acreage-per-well distributions and the remaining drillable areas per sub-area to estimate contingent and prospective resources. The difference between contingent and prospective resources was based on the distance from existing wells.
As of January 2018, the total reserves (P90–P50–P10) for the Vaca Muerta shale in Argentina associated with existing wells are estimated to be 8.5–17.5–38.4 MMm3 of oil and 9.5–27.2–74.6 Bm3 of gas. Estimated contingent resources are 8.8–50.6–181.1 MMm3 of oil and 2.6–16.4–51.5 Bm3 of gas. Estimated prospective resources are 424–2,464–8,771 MMm3 of oil and 211–1,279–3,483 Bm3 of gas. Resources and reserves estimates were combined to estimate technically recoverable resources (TRR). The estimated TRR are 443–2533–8992 MMm3 of oil and 223–1223–3609 Bm3 of gas.
The results of this work should provide a more reliable assessment of the reserves and resources in the Argentine Vaca Muerta shale than previous estimates based on volumetric methodologies and analogies.
Chemical Selection and Simulation for SP Flooding in Puesto Hernandez Field
Authors: Georgiades Diana , Arguello Scotti Agustín , Villarroel Gisela , Martino Luis , Thomann Milagros , Gandi Silvana 
Published: July 2020

Abstract
Potential for EOR development at the historically prolific aeolian Avilé Member in Puesto Hernandez (PH) field led to the simulation of chemical processes in a 3D field-scale static-dynamic sector model; said model is presented to provide a business case for SP flooding. Recovery factor results are compared with the expected final recovery after more than 30 years of waterflooding.
Laboratory core flood experiments and phase behavior tests were conducted to determine the optimum polymer and the optimized surfactant formulation. The modeling of these experiments, allowed the estimation of input parameters for reservoir simulation. A sector model taken from a 3D full field static-dynamic model was used to simulate the effect of surfactant-polymer (SP) flooding over the residual oil saturation, which has almost already been reached in Puesto Hernandez field.
The SP formulation obtained from laboratory experiments, used in the simulation with specific software, gave way to the identification of significant volumes of oil in the PH field which could be recovered with chemical processes by reducing the residual oil saturation. The results from the evaluation of two pilot zones showed promising outcomes: the residual oil saturation would be reduced to around half its original value. A surfactant-polymer pilot is currently being designed to be implemented during the year 2020. This pilot can lead to the extension of this methodology to other mature fields expanding the YPF portfolio.
This paper provides valuable insight into SP flooding simulation to assist engineers in analogous mature fields evaluating this recovery methodology. Key parameters for forecasts, business case definition and estimation of the total resources of the Puesto Hernandez field are identified.
Minimum Economic Field Size and Probability of Success of Conventional Hydrocarbon Discoveries, in the Light of the New Open Uruguay Round Framework
Authors: Ferro Santiago , Rodríguez Pablo , Tomasini Juan , Gristo Pablo , Blánquez Natalia , Conti Bruno , Romeu Cecilia , Marmisolle Josefina 
Published: July 2020

Abstract
Recently, it was announced the first oil recovered in surface onshore Uruguay, in Norte Basin. Additionally, operators and Uruguayan National Oil Company (ANCAP) have identified many prospects, which are almost ready to be drilled, at different water depths offshore Uruguay. Therefore, it is relevant to know the minimum volume of hydrocarbons contained in hypothetical conventional discoveries, necessary to make the projects economically feasible in the light of the new Open Uruguay Round fiscal regime, both onshore and offshore.
The prospective resources distribution was calculated for several prospects, which were identified with 2D and/or 3D seismic, and are located onshore and offshore at various water depths. The probabilistic cash flow analysis including forecasts for production, capital and operating costs, product prices and the new fiscal regime was conducted in all cases to define the breakeven oil prices and the Minimum Economic Field Size (MEFS). Finally, the Net Present Value, the probability of geological success and the probability of development were considered to complete the expected monetary value and the probability of commercial success calculations.
Many aspects can be taken away from this work. Firstly, as a general trend, the MEFS and the breakeven oil price required for the prospects increase with water depth, reflecting the rise in expenditures. However, specific prospect parameters may cause a separation from this clear trend. Likewise, the decision to sell or reinject natural gas has a significant influence on project profitability. Additionally, the probabilities of geological success, in the abscense of productive analogues in the south Atlantic, are still low in all cases, reinforcing the status of frontier exploration of the Uruguayan sedimentary basins. Hence, with the objective to overcome this weakness and encourage exploration, the minimum government take established in the new Open Uruguay Round regime is fairly low. In conclusion, projects onshore and offshore could be equally profitable and successful, requiring higher size of discoveries and price of products as water depth increases. However, because of the remarkable difference in investment and costs, onshore opportunities fit for smaller companies’ portfolios and ultradeepwater prospects are almost exclusive for the majors.
This paper presents new and useful information to geoscientists, engineers and managers of International Oil Companies (IOCs) evaluating exploratory projects in Uruguay, as it includes the novel fiscal regime in force. Finally, it proposes an innovative methodology to calculate the MEFS, breakeven oil prices and the probability of commercial success from the stochastic model.
A Subsea Capping Operation is Not Rocket Science… or is it?
Authors: Cuthbert Andy 
Published: July 2020

Abstract
Technologies addressing subsea source control incidents have advanced over the years, but certain assumptions regarding the capabilities necessary to land a capping stack on a blowing well have not changed. Further research into the forces that must be overcome and the methodology to address those forces during deployment of a capping stack have revealed some startling aspects previously unrecognized.
During a subsea blowout when buoyant, multiphase fluid is released into the environment, accurate prediction of flow dynamics is necessary to evaluate capping stack intervention. To understand the capability necessary to land a capping stack onto a blowing well, the incorporation of flow rate, gas/oil ratio, exit geometry, and metocean conditions are required to create a high-fidelity analysis.
Landing dynamics assessments must incorporate Computational Fluid Dynamics (CFD) for multiphase simulations of release and jet interaction. Years of refining the predictive methodology and simulation have been evaluated against full-scale field experiences. Conventional methodology to deploy and land a capping stack, using vertical or offset deployment, assumes a number of factors except the effects of the flowfield velocities, turbulence, and mixing produced by a blowing well.
The adoption of ongoing research principles into plume-force dynamics, using methodology developed by NASA, has produced a cutting edge approach to analyzing the hydrodynamic flowfield produced by a subsea blowout, adding vital information to the process and successful execution of a subsea capping operation.
This paper offers insight into the high-resolution, high-fidelity plume-force modeling that provides vital information necessary to successfully land a capping stack in shallow or deep water environments.
Leveraging Phylogenetic Trees to Assess Variability of Reservoir Models
Authors: Soriano-Vargas Aurea , Rollmann Klaus , La Rosa Almeida Forlan , Davolio Alessandra , Hamann Bernd , José Schiozer Denis , Rocha Anderson 
Published: July 2020

Abstract
Numerical simulations use past reservoir behavior to calibrate models used to predict future performance. Traditionally, this process is carried out deterministically through history matching and most current approaches focus on developing probabilistic procedures, called data assimilation, whereby reservoir simulation models are calibrated to reproduce plausible performance under different operating conditions.
The output of different data-assimilation strategies can over-reduce the variability by having several highly-similar scenarios. Consequently, the need to ensure the variability of simulation models arises, to consider multiple possible solutions. In this vein, we introduce a visual analytics approach, based on phylogenetic trees, as a means to evaluate the variability of numerical reservoir simulation models throughout the probabilistic data assimilation process. Phylogenetic trees arrange simulation results based on similarity and visually convey match quality through color encoding.
We applied our methodology to two scenarios: (i) a synthetic scenario to exemplify the properties of the phylogenetic tree for the analysis of simulation models; and (ii) two different ensembles of simulation models, each representing a data-assimilation iteration, from the UNISIM-I-H benchmark case based on the Namorado Field, Campos Basin, Brazil.
Our strategy is intuitive and easy-to-use, allowing the user to assess the similarity of the numerical reservoir scenarios, ensemble variability, and match improvement during data assimilation iterations.
Probabilistic Analysis of Loss of Primary Safety Barrier During Drilling Operations
Authors: Sansoni Umberto , Silva Hiago , Gabardo Tainan , Negrão Cezar , Guinho Barbosa Agremis , Wohlers Diego , Waldmann Alex , Colombo Danilo , Leibsohn Martins André 
Published: July 2020

Abstract
The present study aims to propose a methodology to treat probabilistically the prediction of well bottom pressures during drilling, circulation and tripping operations. The pressure generated by the fluid is the primary safety barrier and its failure can immediately initiate gains and losses events in the well, with a direct impact on the safety of the process.
Two models were considered in the study: a two-phase flow model commonly used to predict hole cleaning and downhole pressures while drilling and a pressure propagation single flow transient model (which considers fluid compressibility and gelation) to account for peaks in tripping and pump restarts. A Monte Carlo method coupled with a latin hypercube strategy was implemented to propagate the uncertainties in the input variables to the resulting pressure.
The probabilistic approach aims to consider the uncertainties in the input variables (weight, rheology, penetration rate, drillstring velocity and acceleration, pump flow, particle diameter, well trajectory, etc.). Monte Carlo Simulation was conducted to generate the pressure distribution curves in each of the operations: drilling, circulation, tripping and pump restarts. Probabilistic pressures are fit into probabilistic operational windows allowing the quantification of the risk of losing the barrier. The paper also details the critical aspects associated with typical pre-salt well drilling project conditions in offshore Brazil where narrow operational widows are a reality. The analysis directly impacts the choice of drilling strategy (conventional or MPD) and, consequently, rig selection.
Innovative strategy to enable risk assessment strategies in the analysis of safety barriers. Pilot to a major integrated approach which will include other barriers such as cement, rock and equipment.