bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling Fractured Horizontal Wells As Dual Porosity Composite Reservoirs – Application to Tight Gas, Shale Gas and Tight Oil Cases
Authors: Brohi Imad , Pooladi-Darvish Mehran , Aguilera Roberto 
Published: May 2011

Abstract
Multiply-fractured horizontal wells are an efficient way to produce from tight gas, shale gas and tight oil formations. In this work, we present a linear composite model with a dual porosity inner zone to model production from a multiple fractured horizontal well. The composite solution uses linear dual porosity flow solution for the inner reservoir and a linear single porosity solution for the outer reservoir combined with continuity of pressure and flux at their interface. Solution to the problem was obtained in Laplace space. The solution that we have obtained is simple and fast, yet effective and can be applied to model production from fractured horizontal wells.
For the cases of interest, we observe three linear flow periods in this model. The first linear flow is from the fractures into the wellbore, followed by linear flow in the matrix to the fractures and lastly linear flow in the outer single porosity reservoir to the inner reservoir. Each of these three linear flow periods is separated by a transition depending on the properties of the fracture, matrix and the outer reservoir.
We use a numerical simulator to examine the validity of some of the assumptions made in the development of the work. While the model that we have made consists of only linear flow solutions, the numerical model accounts for two dimensional flows in all media. New solutions are presented in the form of type curves.
The Effects of Wall Slip in a Couette Rheometer When Measuring and Comparing Hydraulic Fracturing Fluids
Authors: Churchill Scott 
Published: May 2011

Abstract
The most common apparatus to gather rheological properties on hydraulic fracturing fluids is the Couette rheometer. It functions by rotating a pressurized cup filled with a sample of the fluid around a bob. The rheometer calculates the apparent viscosity and power law values by measuring the friction between the bob, the fluid, and the cup based on the deflection of the bob at different shear rates of the rotating cup. With this sort of apparatus, the assumption is made that any "slippage" that the fluid encounters at the wall's surface is negligible. Although this assumption may be valid with other types of fluids such as those within the food or cosmetics industry, due to the unique characteristics of hydraulic fracturing fluids this is not always the case. Based on a rhelogical study of three different types of hydraulic fracturing fluids presented in this paper, conclusions were drawn on the effects of wall slip when measuring and comparing different types fracturing fluids and how this wall slipping phenomenon can be minimized. In this study three types of fracturing fluids were tested: a borate crosslinked water based gel, a surfactant water based gel and a hydrocarbon based gel. The water based gels demonstrated a significant amount of wall slip due to a phase separation of the water and gel. No phase separation was found in the hydrocarbon based fracturing gels, as such no wall slippage was observed. Several different metals were tested with varying surface roughness in order to attempt to minimize slip. Non-corrosive metals with a roughened surface allowed for higher viscosity readings in the water based gels. The surface roughness played a minimal effect in the viscosity readings for hydrocarbon based gels.
Viscosity Reduction EOR with CO2 & Enriched CO2 to Improve Recovery of Alaska North Slope Viscous Oils
Authors: Ning Samson , Jhaveri Bharat , Chambers Bret , Jia Na , Gao Jinglin 
Published: May 2011

Abstract
Carbon dioxide can be used as an injectant in Viscosity Reduction Water-Alternating-Gas (VRWAG) Enhanced Oil Recovery process for viscous oil reservoirs. The design of a VRWAG process with CO2 requires a series of laboratory data in order to properly understand the CO2 / reservoir fluid phase behavior and accurately model the reservoir performance. This study involved both laboratory experiments and reservoir simulation to investigate the effect of the phase behavior of the oil-CO2 system on the recovery of the Alaska North Slope viscous oils.
The laboratory experiments includes two four-step backward multiple-contact experiments (MCE) with pure and enriched CO2 added to Alaska North Slope viscous oil to investigate the phase behavior of the mixtures of CO2 and live reservoir fluid. The enrichment was achieved by mixing 85% of CO2 with 15% of natural gas liquids (NGL). Experiments were performed to determine the fluid compositions and other pressure-volume-temperature (PVT) properties such as saturation pressure, gas/oil ratio, liquid phase viscosity, and k-values under reservoir temperature and pressure conditions to simulate the dynamic behavior of the VRWAG process in viscous oil reservoirs. Precipitation of asphaltenes associated with the increase of carbon dioxide concentration and the number of contacts was also investigated.
The MCE experiments showed that pure CO2 could reduce the oil viscosity from 122 cp to 17 cp and that NGL-enriched CO2 could reduce the oil viscosity from 122 cp to 6 cp. These experimental data were used to verify a newly developed equation of state (EOS) which was then used in a numerical simulation model to predict the performance of CO2 flood process in viscous oil reservoirs. Simulation results showed that the VRWAG process could increase oil recovery factor by 10 percentage points with pure CO2 and 11 percentage points with NGL-enriched CO2, which represent an improvement of 44% and 50% respectively over the waterflood process.
Implementing Integrated Solutions for Reservoir Management: San Joaquin Valley Case Study
Authors: Popa Andrei , Horner Katie , Cassidy Steve , Opsal Steve 
Published: May 2011

Abstract
To achieve more efficient business processes by exploiting data and knowledge management, real-time systems and advanced analytical tools, most major integrated and service companies have developed, or are in the process of developing, intelligent programs also known as Digital Oil Field of the Future3. The i-field™ program represents Chevron's efforts to integrate people, processes, technology and information to achieve its vision of Upstream Transformation. Ultimately, this vision translates to higher-quality decision making and changes the way we operate our assets.
A new multiyear i-field™ program, Integrated Reservoir Management (i-RM), was initiated in the San Joaquin Valley to enable efficient reservoir management (RM) and quality decision making for heavy oil assests operating under steamflood EOR technologies.
The paper describes the journey undertaken by the project team to build a proprietary steamflood integrated reservoir management tool that answers the basic neverending engineering requirements: instant access to clean data, single source of information for everyone and seamless data-tools linkage. The ultimate benefit is not only increased time spent by engineers and earth scientists to analyze data but also consistent project design workflows and decision making processes across fields. In addition to above documented benefits, the manuscript includes operator's experience with project framing, development, deployment and user-acceptance.
Programs Enable Operational Excellence in a Challenging Environment, Pushing the Limits of Large Data Transfer for Real Time Monitoring and Surveillance Operations in San Joaquin Valley
Authors: Popa Andrei , Barrett Mark , Cassidy Steve 
Published: May 2011

Abstract
Chevron's San Joaquin Valley (SJV) Business Unit (BU) is a mature, heavy oil, thermally enhanced asset consisting of large fields that have been producing for over a century. To ensure continuing technology transformation, in 2003 San Joaquin Valley started its own i-field program being among the first BUs to pursue Chevron's enterprise-wide effort in building the Digital Oil Field of the Future. From its initiation, the program has been focusing on creating solutions to manage and optimize operations and enhance recovery.
The paper showcases one of the most technologically advanced i-field heavy oil solutions implemented in San Joaquin Valley thermal assets, involving a high accuracy tiltmeter program implemented by a partner service company to advance the understanding of diatomite operations and monitor the surface ground movement
In 2008, Chevron's SJV i-field team partnered with its Information Technology (IT) department to develop a state-of-the-art application called Integrated Diatomite Operations Tool (i-DOT). The product incorporated current field workflows for mapping the grid deformation with business data (well locations and status, steam volumes and dates, etc.) in relevant time. This was accomplished by establishing a live connection between Chevron and partner service company servers whereby terabytes of grid data would flow seamlessly into Chevron's SJV servers. Data acquisition, data processing and storage efforts were accomplished through an integrated effort between IT, GIS and PetroWeb development teams. Workflows were built through close collaboration between i-field engineers, petroleum engineers, earth ecientists, IT professionals and the operations group.
The i-DOT solution has become the single point of operation monitoring and activity scheduling for multiple groups such as Operations, Asset Development and the Drilling team. The benefits of implementing i-DOT solutions are significant and transformed our decision making process in diatomite fields. The paper includes not only value creation but also lessons learned during development, deployment and end-user acceptance.
A Data Mining Approach to Unlock Potential from an Old Heavy Oil Field
Authors: Popa Andrei , Cassidy Steve , Mercer Mark 
Published: May 2011

Abstract
This paper presents an integrated lookback approach on analyzing historic reservoir performance in a California asset using data driven technologies. Being characterized as a heavy oil asset, with oil gravity between 6 to 12 API, a wide range of cyclic steam practices combined with diluent injection was used to produce the field. Drilling and cyclic steam activity in the field reached a peak in 1984 followed by a sharp decline in 1986 due to low oil prices.
A set of data mining tools including regression, clustering techniques, and neural networks was used in the study to understand past operation practice and performance. In the first stage, using well locations, completion data, production history, and target sand depths zonal allocations of production was estimated. The second stage established the cyclic steam response of the different formations. Along the way, data driven tools were used to identify the common and best practices in the field.
The data driven technologies and tools used in this study proved to be a fast and thorough approach for examining large data sets and extracting powerful knowledge. This approach was applied and executed in a portion of a heavy oil field in California and provided the fundamental understanding for future re-entering and development of the asset.
Application of Case-Based Reasoning for Well Fracturing Planning and Execution
Authors: Popa Andrei , Wood William , Cassidy Steve 
Published: May 2011

Abstract
Over the last two decades, there has been significant activity in the soft computing arena with focus on various computer paradigms such as neural networks, genetic algorithms, and fuzzy logic to more efficiently solve complex engineering problems. Further work concentrated on integrating two or more of these paradigms has led to what is known as "hybrid systems." The power of the hybrid system relies on the fact that technologies are intended to complement each other and exploit their individual strengths to enhance solution generation.
Case-based-reasoning (CBR) is another soft computing technology developed to deal with uncertainty, approximate reasoning and exploit knowledge domain. Case-based reasoning, also known as computer reasoning by analogy, is a simple and practical technique that solves new problems by comparing them to ones that have already been solved in the past, thus saving time and money.
This paper provides a general framework of case-base reasoning along with a review of the four-step cycle that characterizes the technology (retrieve, reuse, revise and retrain), followed by a specific application to well fracture treatment design, planning and execution. The proposed methodology extracts the relevant historical information recorded during field job execution, utilizes a rule-based system to make adaptations, and then suggests the most appropriate solution for new well fracturing candidates. The technique was tested as a front-end tool using sample data from a tight gas field with significant hydraulic fracturing activity. This simple case demonstrates how case-base reasoning can be applied to improve hydraulic fracturing design, planning and execution of wells, thus significantly increasing the job execution success while avoiding known pitfalls. In addition, the work demonstrates the value of captured "on-site" experience and shows the advantages of using intelligent systems in decision making.
A High-Resolution Approach in Predicting Reservoir Performance from Diatomite
Authors: Akhimiona Nosa , Corbett Patrick W. , Lewis Ken 
Published: May 2011

Abstract
Managing a waterflood in a diatomite reservoir faces a number of challenges, such as oil recovery, performance matching, optimum well spacing and subsidence. Another issue is the paucity of studies done on the diatomite reservoir, as most studies in petroleum engineering are based on the performance of more conventional clastic /sandstone or carbonate reservoirs. So, applying some of these concepts in a diatomite reservoir can lead to erroneous results. A better understanding of the relationship between the geology and reservoir performance cannot be overemphasized, especially where the reservoir is a diatomite reservoir with no known analogue.
Improving the recovery from diatomite reservoirs has been a problem since first production in the 1890's. In 2007, horizontal wells were drilled in the Lost Hills field and supported with vertical water injectors to improve recovery. These wells are fractured hydraulically to improve drainage and conductivity. However, the oil production performance results from these wells were below expectation. Some of the wells watered out, others were fraught with ‘sanding’ and other operational issues. This study looks at effective ways of scaling kv/kh which is critical to matching production performance.
A good numerical model that incorporates understanding of the geology proved important to be able to predict performance from wells. The geopseudo approach, a multiphase flow upscaling methodology, is used in this study. It incorporates flow/structure interaction at the lamina level. The conclusions and recommendations from this study will provide an insight through which petroleum engineers will be able to build a robust simulation model needed for predicting well performance and also help in making data driven decisions with respect to field development.
Experimental Investigation of In Situ Combustion at Low Air Fluxes
Authors: Alamatsaz A. , Moore R. G. , Mehta S. A. , Ursenbach M. G. 
Published: May 2011

Abstract
The oil industry has inherited a mixed history of success and failure of application of air injection as an enhanced oil recovery method. Close scrutiny of these projects shows that in order to conduct a successful in situ combustion oil recovery project, sustained propagation of the combustion front within the reservoirs is a must. Sufficient air must be supplied to maintain the propagating combustion front in the desired bond scission (carbon oxide forming) mode otherwise unfavorable oxygen addition i.e. Low Temperature Oxidation (LTO) reactions will consume oxygen and not mobilize oil. When this happens, the combustion process is deemed to be exhausted.
Quantification of the minimum air flux required for sustaining combustion zone propagation is needed to properly match the capacity of the air injection facility to the volume of reservoir which is to be swept by the thermal zone. Undersizing of the air injection capacity causes the in situ combustion process to become inefficient when only a small portion of the reservoir has been "burned".
One-dimensional combustion tubes (CTs) are conventionally used to obtain important combustion parameters required for designing an air injection project. Due to the high heat capacity of laboratory equipment designed for elevated temperature and pressure operation, oxygen addition or LTO reactions are promoted by the heat transfer through the core holder walls when the laboratory tests are performed at low air injection rates. Therefore, when operated at elevated pressures, the CTs are unable to operate at the low air fluxes required to establish the minimum possible air injection flux while maintaining the combustion reactions in an effective mode.
To address this issue, a state of the art combustion cell was conceived and utilized as a way of addressing the above mentioned constraints associated with high pressure one-dimensional combustion tubes. A conical combustion cell design was built as it enables continuous air flux reductions without having to adjust the air injection rate. The heater control strategy was also modified in order to address the lag-lead operation often used for one-dimensional combustion tubes. To date, the unit has operated at air fluxes down to 3 sm3/m2∙h.
This experimental work described in this paper provides insight into the limitations in laboratory investigations of in situ combustion as well as the expected behavior of field applications of the in situ combustion process.
Recovery Mechanism of Steam Injection in Carbonate Reservoir
Authors: Tang Guo-Qing , Lowry Dustin , Lee Vincent 
Published: May 2011

Abstract
Thermal processes application in carbonate heavy oil reservoir is less successful than sandstone reservoir due to its feature that is naturally fractured and oil-wet condition. The enhanced oil recovery by steam drive in carbonate reservoir is often low because the steam easily bypasses oil which is locked in low permeability matrix. In addition, the recovery mechanism by steam injection is not well understood so far. The research from last decade showed that recovery mechanism is dominated by complicated interactions between oil/brine/rock and mineral heterogeneity. Imbibition and drainage may dominate the heavy oil recovery from fractured carbonate reservoirs when the steam is injected.
This work presents an experimental study that was designed to characterize the recovery mechanism of steam injection in heavy oil carbonate reservoir by simulating the reservoir conditions. Several reservoir rock samples with a length of 3 inches and a diameter of 1.5 inches were used for both free and forced imbibitions at elevated temperatures. The crude oil from the same formation has an API gravity of 14 and a viscosity of 5624 cp at room temperature was used as oil phase. The water phase was either synthetic formation brine or 5000 ppm NaCl brine. A high resolution CT scan imaging technology was used for screening core candidates and cutting the core plugs to avoid a significant difference in core properties which may affect recovery mechanism.
This study revealed that the oil recovery from carbonate reservoir by steam flooding is mainly dominated by imbibition, viscosity reduction, and in-situ steam generation inside the core. The increase in imbibition oil recovery is strongly dependent on the interaction between the oil/brine/rock which in turn affects the wettability rock. Effluent brine chemistry analysis verified that carbonate dissolution is associated at a temperature above 300°F, which may result in wettability alteration toward water-wetness. The oil recovery by free imbibition increased from around 10% OOIP to 50% OOIP as the temperature is increased from 100 to 400°F. If the pore pressure is suddenly reduced from 350 psi to room atmosphere pressure at 400°F (in-situ flashing process), the oil recovery can be further increased to 60–70% OOIP due to a significant amount of steam is generated in-situ. Correspondingly, the rock compaction is observed during the flashing process. The measured rock compaction is less than 4% of the total pore spaces. Compared with free imbibition, forced imbibition at low temperature gives higher oil recovery at low temperature, but does not show significant increase in oil recovery at high temperature.
Thermally Induced Fracture Reconsolidation of Diatomite Under No Flow Conditions
Authors: Vega B. , Tang G. Q. , Kovscek A. R. 
Published: May 2011

Abstract
Diatomite reservoir rocks are characterized by high porosity (35–70%), low permeability and have a favorable response to thermally enhanced recovery methods. Fracture reconsolidation or healing occurs, in some cases, during heating of diatomite. Silica dissolution is considered one of the main mechanisms that leads to fracture consolidation. Alkaline brine solutions have been found favorable to silica dissolution and therefore, fracture healing. The objective of this work is to delineate the impact of the application of elevated temperatures and confining pressure under no flow conditions on core-scale fracture reconsolidation of fractured diatomite samples where the silica is in either opal-A or opal-CT phases. A series of isothermal experiments was conducted over a range of temperatures between 45 and 230 °C, a range of confining pressures between 100 and 700 psi, and minimum flow of brine as the aqueous phase. Fractures were created parallel and normal to the core length. Fracture reconsolidation was verified as reflected by changes in permeability and porosity of the samples, by image analysis provided by CT scan X-ray tomography and by visual inspection after the tests. Increasing temperature resulted in a trend of decreased permeability as the result of the permeability loss due to compaction and reconsolidation of the fractured area. Results suggest that fracture healing in diatomite occurs even under minimum aqueous phase conditions, when combined with a dose of confining pressure and elevated temperatures.