bluuebunny/crossref_metadata_2025_split huggingface dataset:
Constraining the Conditions of Scale Deposition in a Gas Condensate Well: A Case Study
Authors: McCartney R. A. , Duppenbecker SPE, S. , Cone R. 
Published: February 2021

Abstract
Field X is a gas condensate field where the wells produce primarily gas and a small amount of formation water mixed with condensation water (&lt;19 Sm3/d per well). Unexpectedly, scale (aragonite, possibly with minor sulfate minerals) was identified in Well A during a routine PLT. To aid scale mitigation planning, the cause of scale deposition has been investigated using scale prediction software.
A wide variety of data and information has been used to constrain and verify the scale predictions and as a result they are consistent with the observed type, volume and location of scale, PLT results (inflow temperature, hydrocarbon flow profile), produced water and formation water Ca and Cl concentrations, and production data (hydrocarbon and total water rates). A novel method was developed to estimate the composition of formation water entering the well from produced water analyses (mixtures of condensation and formation water) and where produced water rates are available this can also be used to estimate the rate of flow of formation water into the well.
The results suggest that formation water enters the well at low rates (∼1m3) from the upper perforated zone (Formation 1) whilst water-saturated hydrocarbons enter from both the upper and lower zones (Formations 1 and 2). The formation water Cl concentration is between ∼5, 100 and ∼11, 000 mg/L and the Ca concentration may be between ∼121 and ∼177 mg/L. Partial evaporation of formation water (due to pressure decline and Joule-Thomson heating) as it enters the well causes scale deposition. The remaining formation water is produced along with water condensing from gas. An additional risk of total salt deposition in these wells was also identified.
This study has shown how a wide range of data can be used to constrain the conditions of scale deposition in such wells. The results of this study are being used to develop scale management plans for the field.
Test Method Development and Scale Inhibitor Evaluations for High-Salinity Brines in the Williston Basin
Authors: Lu Haiping , Haugen Chris , Garza Tim , Russek Jeffrey , Hughes Baker , Harbaugh Chad 
Published: February 2021

Abstract
In the Rocky Mountain region of the United States, high-salinity brines (total dissolved solids &gt; 250, 000 mg/L) present during oil and gas production cause severe scale problems in the Williston Basin. The scales include not only calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, but also sodium chloride (halite). This paper presents the development of test methods and their corresponding testing results for scale inhibitor evaluations in the laboratory and their applications in the field for high-salinity brines.
It is well known that there is no effective test method for halite scale inhibitor laboratory testing due to the difficulty of controlling the amount of halite precipitation and reproducibility in the test. The evaluation of scale inhibitor performance was conducted by using a tube-blocking test and a static bottle test with synthetic high-salinity brines from the Williston Basin. Two sets of brines were designed, based on the field brine, and were tested with two methods. One set of brine was for halite scale inhibitor evaluation by mixing near-saturated NaCl synthetic brine with a highly concentrated brine of CaCl2·2H2O + NaCl. The second set of brine was designed to evaluate scale inhibitor performance on calcium carbonate, calcium sulfate, barium sulfate, and strontium sulfate by modified brines. Three types of scale inhibitors were used for the performance evaluations, including halite scale inhibitors, general scale inhibitors, and a multifunctional scale inhibitor. The lab test results showed the multifuntinal scale inhibitor exhibited good scale inhibition performance for both sets of scale testing. Successful scale inhibitor implementations in the field applications and case history are also presented in this paper.
Liquid Scale Inhibitors for Metallic-Crosslinked Gel Fracturing Systems
Authors: Yue Zhiwei , Fu Qiang , Lang Nancy , Fan Chunfang 
Published: February 2021

Abstract
Scale inhibitors are important additives in fracturing fluids to help prevent mineral scale depositions during hydraulic fracturing, shut-in, and flowback stages. The inhibition mechanisms rely heavily on the interactions of certain functional groups from the inhibitor molecules and the lattice metals on the scale crystal surface. In stimulation using crosslinked gel fluids based on metallic crosslinkers, such as zirconium (Zr), titanium (Ti), or aluminum (Al), these metals form strong covalent bonds with guar and guar derivatives and therefore significantly increase overall gel stability. When anionic liquid scale inhibitors are present, the crosslinker metals are susceptible to attack from scale inhibitors because of similar interactions, often resulting in lower viscosity and compromised fluid performance. For this reason, liquid scale inhibitors are usually pumped in prepads during many fracturing treatments. During these treatments, fracturing fluids from other stages and reservoirs that contact these fluids are not protected from scale deposition. Although this incompatibility issue is an important factor in designing fracturing fluid systems, the authors have not found sufficient prior literature providing valid solutions other than applications of time-released solid scale inhibitors.
This paper investigates the interferences of various types of liquid scale inhibitors on Zr-based crosslinkers. Their chemical compatibilities are evaluated in terms of crosslinked viscosity stability and scale inhibition efficiencies. Data presented in this paper indicate that two polymer-based liquid scale inhibitors can be added to selected Zr-crosslinked fluids with minimal impact on crosslinking performance. Scale inhibition efficiency can be maintained by adjusting the pumping flow rate to compensate for the effect of Zr-based crosslinkers.
Mechanisms, New Test Methodology and Environmentally Acceptable Inhibitors for Co-deposition of Zinc Sulfide and Calcium Carbonate Scales for High Temperature Application
Authors: Tortolano Christopher , Chen Tao , Chen Ping , Montgomerie Harry , Hagen Thomas , Benvie Ronald , Zou Lucy 
Published: February 2021

Abstract
Zinc sulfide (ZnS) is one of the notoriously exotic scales formed in the high temperature oil fields. Its formation can potentially cause severe scale issues by itself or combined with conventional CaCO3 scale. Limited publications are available on ZnS deposition/inhibition, let alone the combined ZnS and CaCO3 scales. The mechanisms of these scale interactions are still unknown.
The relatively small amount of ZnS precipitated that adheres to surfaces and its ‘soft’ scale characteristic make it difficult to test ZnS using traditional scale inhibitor evaluation test methods, especially at high temperature. A new methodology with modified dynamic loop test combining the traditional test coil and novel test filter system has been developed and allows evaluating ZnS and combined ZnS/CaCO3 at high temperature in the absence and in the presence of scale inhibitors.
Co-deposition of ZnS/CaCO3 and the interference between ZnS and CaCO3 have been studied at elevated temperature. The mechanisms have been addressed by both scale prediction and laboratory tests. Findings from this study show that ZnS dramatically accelerated CaCO3 formation within the test brine and made the scaling condition extremely harsh, even with a very small amount of ZnS present.
Several types of inhibitor chemistries were short listed for this study based on a previously published mechanism study to assess their ability to prevent ZnS and co-deposition of ZnS/CaCO3 at elevated temperature. Type-1 inhibitor is dispersion/nucleation, type-2 is nucleation/growth and type-3 has no inhibition function on ZnS. The test results conducted at 170°C agree well with the mechanism assumed by the previous mechanism study, and the inhibition mechanisms are reinforced. The minimum inhibitor concentration (MIC) of scale inhibitors has been evaluated for CaCO3 and co-deposition of ZnS/CaCO3 at 70°C and 170°C. The difference of MIC gives an indication of the negative effect that very small amounts of ZnS can have on the inhibition of co-deposition. The performance of environmentally acceptable inhibitors is also presented for this challenging environment.
This paper presents a comprehensive study of the challenge of ZnS and co-deposition of ZnS/CaCO3 under conditions similar to that of many of the current HT/HP field developments in the North Sea and recent developments in the Gulf of Mexico.
Lessons Learned from Production History Matching in Single Cell Numerical Models in an Integrated Asset Model
Authors: Noguera C. 
Published: February 2021

Abstract
Integrated Asset Modeling (IAM) approach1 is defined as simultaneously modeling the flow through the reservoir up the wellbore and through a surface network. Reservoir simulation history matching is one of the most complex and time consuming process, however, it ensures that the model developed is useful for forecasting and management decisions. By nature, an Integrated Asset Modeling model can be made up of hundreds of nodes, making it complex and difficult to manage if a proper methodology is not implemented to allow an effective history matching, especially when developing all the components of the IAM model.
The purpose of this paper is to share lessons learned from a methodology that allows the development of reservoir models via material balance, proper matching of wellbore models and wellbore tests; calibration of the surface network and ultimately, history matching of an Integrated Asset Model, following rigorous quality assurance and quality check procedures. Issues addressed include: characterization of the reservoir-wellbore system, knowledge of main drive mechanisms, aquifer uncertainty, tubing flow assessment.
The methodology enabled production history matching of 15 producing gas wells; ensuring that the IAM model developed is therefore a reliable forecasting tool. In addition, Simulation run time reduction was achieved by switching from a rate dependent constrained system to a pressure drop dependant system.
Production history matching should precede any numerical simulation study, as it provides useful knowledge of the properties and characteristics of the reservoir-wellbore-surface network, leaving little room for adjustments, which constitutes an excellent starting point for numerical models; hence an IAM approach represents basis for the construction and quality check of more rigorous multi cells numerical reservoir simulation models.
An Integrated Approach Using Geomechanics and Advanced Rock Characterization Techniques to Optimize Reservoir Productivity and Stimulation Design
Authors: Nguyen M. , Worku T. , Mitchell W.P. , Lakshmikantha M.R. , Hegazy M. 
Published: February 2021

Abstract
Accurate prediction of geomechanical rock properties is one of the main challenges to be overcome in E&P projects, in order to optimize well completion design and stimulation strategy. This is especially so in the early stages of a project, e.g the appraisal phase. In the recent years, Scratch Testing has become an emerging geomechanical characterization technique that is used to determine the mechanical properties of the rock. With this method, a groove of fixed depth (typically less than 1 mm) is scratched on the rock surface. The forces acting on the cutter are recorded at a high sampling rate (about 10 samples per millimeter), with high precision and resolution (about 1 Newton). This scratch test data is then used to characterize the length of heterogeneity of the rock, and to generate the geomechanical properties profile (rock strength, friction angle). Presently, such valuable information is only partially integrated with petrophysical and geological data. A series of Scratch tests are performed on different rock samples and types to create a continuous rock strength profile, which is then integrated with sedimentology, core analysis and wireline logs. This data assimilation led to the development of, a new technique to assist in the extrapolation of rock strength in un-cored intervals/wells. In this paper, the developed workflow will be further elaborated, along with its results and applications to support the design of a fit for purpose well completion and stimulation strategy, which is a key component in the field development planning phase of an E&P project.
Software Tool for the Study, Analysis and Evaluation of Enhanced Oil Recovery Processes
Authors: Delgadillo-Aya C. L. , Trujillo-Portillo M.L. , Palma-Bustamante J.M. , Niz-Velasquez E. , Rodríguez C. L. , Leon-Martinez N. E. 
Published: February 2021

Abstract
Software tools are becoming an important ally in making decisions on the development or implementation of an enhanced oil recovery processes from the technical, financial or risk point of view. This work, can be manually developed in some cases, but becomes more efficient and precise with the help of these tools.
In Ecopetrol was developed a tool to make technical and economic evaluation of enhanced oil recovery processes such as air injection, both cyclic and continuous steam injection, and steam assisted gravity drainage (SAGD) and hot water injection. This evaluation is performed using different types of analysis as binary screening, analogies, benchmarking, and prediction using analytical models and financial and risk analysis.
All these evaluations are supported by a comprehensive review that has allowed initially find favorable conditions for different recovery methods evaluated, and get a probability of success based on this review. Subsequently, according to the method can be used different prediction methods, given an idea of the process behavior for a given period. Based on the prediction results, it is possible to feed the software to generate a financial assessment process, in line with cash flow previously developed that incorporates all the elements to be considered during the implementation of a project. This allows for greater support to the choice or not the application of a method.
Finally the tool to evaluate the levels of risks that outlines the development of the project based on the existing internal methodology in the company, identifying the main and level of criticality and define actions for prevention, mitigation and risk elimination.
A Case Study of Integrated Asset Modeling to Support Reservoir Management Strategies for Four Dry Gas Fields Sharing Production Facilities
Authors: Espinola O. , Rocha M. , Alvarez N. C. , Ramirez J.R. , Solis A. , Guzman-Arevalo J.D. 
Published: February 2021

Abstract
The integrated asset modeling has gained popularity in the last years because it has a positive impact on field development, optimization and reservoir management. Especially it has become a must be to properly analyze the interaction between a reservoir and its production facilities or to predict the behavior of several fields sharing a common surface production facility (Ghorayeb, k. 2005).
As a result of the strategic development plan, PEMEX Veracruz Asset has been discovering dry gas fields which must be produced through shared production facilities in order to be economic. This poses a complex operational scenario that demands the use of technology that enables the analysis of the whole system and the interrelation of its elements to support the reservoir management strategies.
This paper describes a case study in which four reservoir models were coupled with a production network model, with the objective to maximize the recovery factor, identify operational problems along the exploitation, and also evaluate the water production impact, through the Integrated Asset Modeling (IAM) enabling the design of different exploitation strategies including compression stages and evaluate them both technically and economically.
Besides it includes a full description of the modeling process with all the assumptions, constraints, solving method and results obtained. This methodology has been successfully implemented adding value to the asset due to a proven improvement in the reservoir management, operational plans and decision making process.
Productivity Prediction of Coalbed Methane Considering the Permeability Changes in Coal
Authors: Chen H. , Li M. , Zhang Y. , Liu C. , Li Y. 
Published: February 2021

Abstract
This paper describes a three-dimensional numerical model for predicting the coalbed methane (CBM) production. The model describes single phase gas desorption from coal matrix, diffusion to the fracture and two-phase flow of gas and water in the natural fracture system as well as the permeability changes in coal which result from effective stress changes and matrix shrinkage due to gas desorption. The model was discretized by a finite difference method. The implicit pressure-explicit saturation (IMPES) method was used to solve the two-phase flow equations and gas desorption equation was solved implicitly.
The numerical model was validated by the field data from Qinshui basin in China. Based on the model, the impact of various reservoir and Langmuir isothermal adsorption parameters on the gas production was investigated.
The results show that the gas production rate of the coalbed methane predicted by this model is in good accordance with the field data. The permeability near the wellbore dramatically decreases as the reservoir pressure drops at the early production period while at the later production period, the permeability near the wellbore increases because of the matrix shrinkage. The permeability changes far away from the wellbore are not so remarkable. In addition, the gas production rate increases with the increased permeability, seam thickness and Langmuir pressure constant while it decreases with the increased porosity and Langmuir volume constant.
The numerical model can be used to predict and analyze the production performance of CBM reservoirs and the research results provide theoretical support for CBM production.
Probabilistic Analysis by Applying Uncertainty Worflows: A Case Study of the Teak Field, East Coast Trinidad
Authors: Segnini C.J. , Rashwan M. , Hernandez M.J. , Rojas J. A. , Infante M.A. 
Published: February 2021

Abstract
This paper presents a methodology for the probabilistic analysis of an infill or step-out opportunity using numerical simulation. Sensitivity and uncertainty analyses for all involved parameters were evaluated through different experimental design techniques. Subsequently, a proxy model was established to reproduce the numerical model performance. Finally, three appropriate solutions were selected from a large population of realizations corresponding to probabilistic percentiles (90%, 50%, and 10% certainty that the specified volume will be recovered).
This proposed methodology helped the asset team to evaluate the well candidates more precisely, confidently, and in less time than the current standard methodology. More knowledge about the variables and their effects on overall outcomes was also gained, which helped the team make more-informed decisions. The workflow used the same numerical modeling software, incorporating and facilitating the changes of both static and dynamic properties simultaneously.
A case study from Teak field, on the east coast of Trinidad, illustrates the applicability of the methodology and compares its results to those obtained using the standard workflow for the asset. The methodology is one of the latest developments in reservoir simulation, and it has not yet been incorporated into the operator's common practices and procedures for exploitation of the TSP fields.
Options for Monetising Deep Water Gas in Trinidad and Tobago
Authors: Alleyne N. A. , Stoute V. 
Published: February 2021

Abstract
Notwithstanding the global thrust to develop renewable sources of energy, fossil fuels, coal, crude oil and natural gas are expected to play a significant role in meeting the world's energy needs for decades to come. Natural gas with the highest hydrogen concentration among the fossil fuels is the preferred fossil fuel from an environmental impact standpoint. Trinidad and Tobago, like the rest of the world, is taking its petroleum exploration activities into deep water, its onshore and continental shelf provinces being fully explored. The development of petroleum reservoirs in deep water has many challenges.
This paper explores the unique challenges posed by developing deep water gas fields with a focus on the options available for monetising the natural gas produced from these fields. The options for getting gas to market are well known and include pipelines, liquefied natural gas (LNG), compressed natural gas (CNG), gas to solid petrochemicals (GTS), gas to liquids (GTL) and gas to wire (GTW). Most of these options are operating in Trinidad and Tobago. The paper evaluates the financial outcomes from applying the pipeline, LNG and CNG options, either offshore or onshore, for gas extracted from deep water fields across a range of reserve levels and well productivities. It aims to establish criteria for deciding which means of monetisation is preferred. The reserve and productivity ranges reflect typical values encountered in the deep water provinces in Latin America, North America and Africa. These provinces account for 85% of all the deep water fields and 74 % the deep water reserves which have been discovered worldwide.
Because the paper focuses on the monetisation of natural gas, its findings will be applicable to any successful deep water exploration in Trinidad and Tobago because all situations, even the discovery of oil, will require that the associated gas be handled. The handling of gas has the potential of being on the critical path in deciding on the development of deep water fields in Trinidad and Tobago.