bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Reservoir Characteristics on Water Production in Enhanced Coalbed Methane Operations
Authors: Jamshidi M. , Jessen K. 
Published: July 2010

AbstractCoalbed methane (CBM) formations deliver a considerable amount of the US natural gas production and have the potential of storing significant amounts of carbon dioxide (CO2) through enhanced gas recovery operations. Enhanced coalbed methane (ECBM) recovery by injection of CO2 or a mixture of CO2 and nitrogen (N2) has been proven to recover additional natural gas resources. However, since coalbeds are normally saturated with water and can be in communication with an aquifer, a large amount of water is often co-produced during the natural gas extraction.The conventional approach for CBM production relies on the reduction of the gas partial pressure in the coal seam. This can be accomplished by either pumping the formation water to the surface or by injecting gas. Disposal of the produced water is an environmental challenge and harmful impurities must be removed. Consequently, a reduction of the water production is desirable.In this paper we present a detailed numerical investigation of the potential reduction in water production during ECBM operations while increasing the methane production. We use a three-dimensional coalbed model with an aquifer located on the bottom to investigate the amounts of gas and water produced in ECBM operations per volume of coal seam as a function of aquifer strength, cleat spacing and sorption characteristics of the coal. The amount of gas/water that is produced varies significantly depending on the aquifer strength. We demonstrate that injection of CO2 and/or (N2) in some settings reduces the water handling problem substantially.CBM is an important worldwide energy source with a large number of formations being excellent candidates for ECBM recovery processes. Our analysis of the interplay between coal characteristics, aquifer support and the resultant behavior in terms of gas/water production and CO2 storage capacity provides valuable new guidelines for future operations.
Estimates of Fracture Lengths and Injection Profile in an Injection Well by History Matching Bottom Hole Pressures
Authors: Suri Ajay , Sharma Mukul M. , Peters Ekwere J. 
Published: July 2010

AbstractAn injection well model is presented that can be used to history match a field injector's bottom hole pressure (BHP) taking into account particle plugging due to injected solids, poro-elastic and thermo-elastic stresses, increase/decrease in injection induced fracture lengths, injector shut-ins / re-starts, changes in injection rates and average reservoir pressure. Estimates of fracture lengths and injection profile as a function of injection time are predicted for a field injector in a multi-layered reservoir.The solids deposition is modeled accurately using filtration theory; the flow of the injection fluids is modeled using approximated composite zones (3 zones with uniform saturation and mobility) and the pressure at the wellbore is calculated using Gringarten's infinite conductivity fracture solution. The injection induced fracture lengths are calculated based on Perkins and Gonzalez fracture propagation model (1985) that accounts for the thermal and poro-elastic stresses. The model is a semi-analytical simulator that can predict injector performance through history matching an injectors’ daily record of injection rate and BHP. More reliable future estimates of injectivity, skin, fracture lengths in a multi-layered reservoir, front locations, and injection fluid profile can be obtained. Both short term pressure transients and long term pressure transients observed over several years of injection need to be history matched to capture effects that are important at both short and long time scales.Finally an example field case study is presented where BHP and injectivity of an ongoing injection well is history matched for both a few short term injection time intervals and over a period of 3 years. It is shown that both the solids deposition and the opening/closing of the injected induced fractures need to be accounted to obtain a good history match. These processes controlled by the layer stresses and the water quality are the most important physical processes determining the injector's injectivity and injection profile.
A Novel Optimization Model for Analyzing Production Data
Authors: Cheng Kun , Wei Y. N. , Wu Wenyan , Holditch S. A. 
Published: July 2010

Abstract
The production data analysis is very important for petroleum industry since it serves as the fundamental step for reservoir development. In computer science, the self-adapting bionic optimization model is a state-of-the-art intelligent computation technique which can be used to analyze production data. In this paper we applied the self-adapting bionic optimization model to analyze production data. This method combines the heuristic approach, grey correlation analysis, and fuzzy clustering method in computer science to optimize the reservoir production plan.
To develop the method, we firstly perform grey correlation analysis to describe the initial correlation between production data parameters. By applying fuzzy clustering method, the production data are divided into different categories according to the degrees of their correlations. This heuristic information is used to construct the production data analysis model. Finally the best-optimized correlations among the various production data can be discovered. A simple example with related parameters is presented to show the algorithmic strategies. This example proved that our method is a flexible and cost-effective quantitative analysis method for production data analysis.
To evaluate this model, we selected 50 wells in some gas reservoirs from Xinjiang oilfield, China. The 50 wells have been developed for several years. Therefore, we have enough data on the 50 wells to be applied in this model. It is demonstrated that this model is useful in production data analysis.
Productivity Loss in Gas Wells Due to Salt Deposition
Authors: Le Duc , Mahadevan Jagannathan 
Published: July 2010

Abstract
Production of gas can result in drying of the near wellbore region due to gas expansion which causes evaporation and hence salt deposition. The deposition of salt leads to a reduction in porosity and permeability of the rock in the near wellbore which then leads to reduction in well productivity. The main objective of this work is to understand the role of salt deposition on well flow efficiency. Particularly, we investigate the effect of capillarity on the salt deposition process in reservoir.
We develop and solve the dimensionless conservation equations for solid salt saturation using numerical methods under radial flow conditions. The results of the calculations show that when the capillary effects are strong, the salt accumulates near the wellbore which leads to plugging and hence higher skin values. The salt saturation continues to evolve until a limiting value, in the rock pores, is reached. Higher values of the limiting saturation leads to a greater reduction in permeability and hence results in a larger skin value for the gas well. The flow efficiency of a gas well, calculated as a dimensionless ratio of the flow with and without skin, decreases continually and asymptotically approaches a constant value.
In a simulation for typical field case we find that the largest increase in skin factor and corresponding decrease in flow efficiency occurs in approximately the first 50 days after which the changes are slower. When connate water salt concentration is higher, the skin value is much higher and hence the well productivity is lower. Using the model developed in this study the decline of gas well productivity due salt deposition can be predicted and hence accurate timing of the well operations such as water wash can be made. Also, the modeling study can be used to select remediation strategies such as wettability alteration to reduce capillarity or application of inhibitors which can reduce the limiting salt saturation by preventing growth of salt crystals within the reservoir rock.
The Effect of Reservoir Heterogeneity on Gas Production From Hydrate Accumulations in the Permafrost
Authors: Reagan Matthew T. , Kowalsky Michael B. , Moridis George J. , Silpngarmlert Suntichai 
Published: July 2010

AbstractThe quantity of hydrocarbon gases trapped in natural hydrate accumulations is enormous, leading to significant interest in the evaluation of their potential as an energy source. Large volumes of gas can be readily produced at high rates for long times from methane hydrate accumulations in the permafrost by means of depressurization-induced dissociation combined with conventional technologies and horizontal or vertical well configurations. Initial studies on the possibility of natural gas production from permafrost hydrates assumed homogeneity in intrinsic reservoir properties and in the initial condition of the hydrate-bearing layers (either due to the coarseness of the model or due to simplifications in the definition of the system). These results showed great promise for gas recovery from Class 1, 2, and 3 systems in the permafrost. This work examines the consequences of inevitable heterogeneity in intrinsic properties, such as in the porosity of the hydrate-bearing formation, or heterogeneity in the initial state of hydrate saturation. Heterogeneous configurations are generated through multiple methods: 1) through defining heterogeneous layers via existing well-log data, 2) through randomized initialization of reservoir properties and initial conditions, and 3) through the use of geostatistical methods to create heterogeneous fields that extrapolate from the limited data available from cores and well-log data. These extrapolations use available information and established geophysical methods to capture a range of deposit properties and hydrate configurations. The results show that some forms of heterogeneity, such as horizontal stratification, can assist in production of hydrate-derived gas. However, more heterogeneous structures can lead to complex physical behavior within the deposit and near the wellbore that may obstruct the flow of fluids to the well, necessitating revised production strategies. The need for fine discretization is crucial in all cases to capture dynamic behavior during production.
A New Management Strategy for Dead Oil Reservoirs With a Strong Aquifer
Authors: Prentt L. A. , Duarte A. G. , Charry W. M. 
Published: July 2010

Abstract
A reservoir management strategy is presented, based on a pressure-production behavior analysis, which was carried out using data from a Llanos Basin’s field in Colombia, applying the concept of Darcy’s Law and Babu-Odeh Equation for vertical- deviated and horizontal wells respectively. The analysis can be applied on dead oil reservoirs (Pres &gt; Pb) providing a surveillance tool for making right decisions regarding the drawdown application as the well is produced, and thus maximizing the recovery factor.
The methodology allows the estimation of the dynamic evolution of skin factor, pressure drawdown and water saturation by well, which are related as well to variables such as water cut (Wcut) and Pwf for an easy handling and understanding of the field for geoscientists, reservoir and production engineers.
This methodology could be applied without the necessity to build a previous simulation model, but in this case a simulation model was carried out, in order to validate the input data, obtaining a good history match. As a result of this, the methodology and numerical simulation model are complementary themselves.
For this case, it was possible to define the proper/wrong application of drawdown increments that improve/reduce (mainly because of sanding) the productivity of vertical, deviated and horizontal wells for specific ranges of water cut.
Planning, Execution & Surveillance of Enhanced Oil Recovery Projects
Authors: Sinanan B. , Budri M. 
Published: July 2010

Abstract
Trinidad and Tobago’s onshore acreage has seen many stages of development. Currently, most onshore fields are well into their mature phase with the application of various forms of artificial lift being applied. Secondary recovery, through water- flooding, has been used in some fields with limited success whilst tertiary recovery methods, namely steam injection, have been more successful. These projects have been few and far between since there is a significant amount of acreage still to be considered for Enhanced Oil Recovery (EOR). An analysis of historical data has suggested that the application of modern day EOR screening, reservoir characterization tools and simulation would address some of the uncertainties that posed problems in the past.
An increasing number of mature oilfield acreage is being leased out by the state to private investors/operators. These entities must be prepared to efficiently exploit these mature blocks by optimizing current production operations, performing recompletions, in-fill drilling but most importantly by adding significant reserves through EOR projects. Many modern considerations within the feasibility stage through to health, safety and environment application must now be adhered to, for successful approvals from government regulators.
This paper provides a detailed outline of the different stages and processes that companies can follow or modify, to suit their reservoir management style, in pursuing successful EOR outcomes. This paper also addresses the importance of EOR screening, project management and surveillance techniques. Processes and recommendations developed from this work can be applied by any oilfield company who wishes to begin or expand their EOR project.
Experimental Investigation of Possibility of Replacing Oil-Based Muds with Environmentally Friendly Water-Based Glycol Muds in Maroon Oil Field
Authors: Saki Y. , Dinarvand N. , Habibnia B. , Shahbazi K. 
Published: July 2010

Abstract
Oil-based muds have been used widely in Iranian oil fields to drill pay zones and shaly formations. However, their applications have become more restricted because of high initial cost and prices of handling. The other important aspect is the environmental concerns that become more stringent in Iran. Therefore, an environmental friendly mud replacement having a good performance has become Iranian oil companies' demand.
Water-based glycol muds seem to be good alternatives for oil-based muds. These environmental friendly muds can inhibit shaly formations, lubricate drill stem, clean the hole, and deposit a thin and impermeable filter cake which reduce the risk of differential pipe sticking and damage, respectively. Moreover, initial and handling expenses are reduced, and these lead to the reduction in the overall costs of drilling the well.
In this study, rheological property of the water-based glycol mud was assessed and compared with the oil-based one. Cutting integrity test was performed in order to evaluate the performance of shale inhibition. This test was conducted on bottom hole samples of Kazhdumi, Daryan, and Asmari, three different problematic shaly formations of Maroon oil field. Formation damage caused by water-based glycol and oil- based muds was measured and compared.
It was found that the water-based mud has a comparable rheological property with respect to oil-based mud. The cuttings recovery percentage was within the excellent range. Formation damage caused by water- based glycol mud was more than oil-based mud. The results show that this mud system is a very good alternative to oil-based muds in Iranian oil fields.
Optimizing Oil Recovery and Carbon Dioxide Storage in Heavy Oil Reservoirs
Authors: Sobers L. , LaForce T. C. , Blunt M. J. 
Published: July 2010

Abstract
We study the design of enhanced oil recovery in heavy oil reservoirs combined with CO2 storage using field-scale reservoir simulation. We consider properties typical of fields offshore Trinidad and Tobago with oils whose density ranges between 940 and 1010 kg/m3 (9-18 degrees API). We first tune a three-parameter Peng-Robinson equation of state to match measured PVT data. We use experimental design to study the influence of oil properties, phase behavior and injection design on oil recovery and net CO2 storage. Carbon dioxide injection into heavy oil reservoirs enhances oil recovery through the mechanisms of crude viscosity reduction, oil swelling and immiscible gas drive. The process involves significant recycling of the injected CO2, but the reservoir is managed to keep as much of the injected CO2 as possible underground.
Trinidad Columbus Basin Petrophysics Field Study Part 2: Permeability and Water Saturation
Authors: Cross K. , Rose H. J. , Ali-Nandalal J. , Teelucksingh S. 
Published: July 2010

Abstract
A petrophysical refresh of the bpTT fields in the Columbus Basin in Trinidad has been carried out. The objectives of the refresh were to provide continuity and consistency in petrophysical interpretations in this mature basin where over the years multiple vendors and differing interpretational approaches have been employed.
In an effort to create a more robust core data set, data gaps were identified in the existing core analyses and supplemental analysis performed. The core data set was expanded to include Co/Cw measurements on plugs from 2 wells to augment legacy data to investigate log-based water saturation methods.
New models were developed for permeability and water saturation and each of these models were calibrated against the core dataset. Permeability was re-evaluated with the new model being based on core-derived measurements and tuned to dynamic well test data to incorporate upscaling heterogeneities. Both log-based and core-based water saturation models were explored. The new core conductivity measurements provided support for the log-based method selected. Air-brine capillary pressure data have provided a key input to the development of a new saturation height function. The match between the new saturation height function water saturation and that derived from resistivity-based saturation is good, reinforcing its validity.
Effects of Fracture Properties on Numerical Simulation of a Naturally Fractured Reservoir
Authors: Noroozi M. M. , Moradi B. , Bashiri G. 
Published: July 2010

Abstract
Effects of Some of the fracture properties on numerical simulation of fractured reservoirs are usually not taken into consideration. Two important fracture properties, which are used in simulation, are fracture capillary pressure and fracture relative permeabilities. Engineers usually assume the first one to be zero and the second one to be a straight line without paying attention to their significant role in the simulation of fractured reservoirs. In addition, effects on these parameters on the behavior of fractured reservoir model when Dual Porosity Dual Permeability (DSDP) concept is used are not investigated yet. The present study investigates the effects of above mentioned properties through other fracture properties like fracture permeability and matrix- fracture transfer coefficient(shape factor) to analyze completely effects of the whole fracture characteristics on numerical simulation of a reservoir. The oil field under study is a highly fractured carbonate reservoir located in Southwest of Iran. This paper indicates when straight-line fracture relative permeabilities and zero fracture capillary pressure can be used in the simulation. Effect of reservoir heterogeneity was investigated on numerical simulation too. Sensitivity analysis also has been done to clearly indicate the behavior of the DSDP model by assuming /nonassuming zero fracture capillary pressure and straight line fracture relative permeabilities. Sensitivity analysis was done in three main production scenarios: natural depletion, water injection, gas injection. This sensitivity study will also show the magnitude of the error which simulation engineers are making if they use straight-line relative permeabilities and zero capillary pressure in the fractures.
Production Optimization in Trinidad and Tobago: Creating Sustainable Performance Through Collaboration
Authors: Samsundar K. , Chandass J. J. , Ramdial A. M. 
Published: July 2010

Abstract
The production optimization team in BP Trinidad and Tobago is a cross-functional team that is focused on optimizing production by safely maximizing the volume of gas available for our midstream customers. This paper will address the challenges faced in a high rate gas business that seeks to improve value is a fixed export regime. It will focus on the processes and tools that have been developed within BP Trinidad and Tobago and how it is being used to increase production.
To date the production optimization team has been able add approximately 5mboed each year through for the last four years through optimization of both the upstream and midstream activities and by managing the current available well stock. The team has also been able to implement new technology for optimizing production conditions called the Trinidad Field Optimizer. All of this is managed through the creation of a sustainable process that seeks to integrate the upstream operations, which includes drilling and new developments, with the midstream customers.
The journey of production optimization has taken four years to move from a place where each department worked in silos, focused on their own performance target, to one where the concept of integration is lived each day. During this time it has become very apparent that only through integration can maximum value be achieved once the right framework is created. Also technology plays a pivotal role in unlocking these hidden barrels. However with the myriad of new tools that is available in today's energy environment, special attention must be spent on selecting the right technology for your business.
This paper will demonstrate both the process and value that has been gained through the work of the production optimization team. It has facilitated integration of the company had has served to increase efficiency.