bluuebunny/crossref_metadata_2025_split huggingface dataset:
A novel multi-rate dual-porosity model for improved simulation of fractured and multi-porosity reservoirs
Authors: Geiger S. , Dentz M. , Neuweiler I. 
Published: December 2011

Abstract
A major part of the world's remaining oil reserves is located in fractured carbonate reservoirs, which are dual-porosity (fracture-matrix) or multi-porosity (fracture-vug-matrix) in nature. Fractured reservoirs suffer from poor recovery, high water cut, and generally low performance. They are modelled using a dual-porosity approach, which assumes that the high-permeability fractures are mobile and low-permeability matrix is immobile. A single transfer function models the rate at which hydrocarbons migrate from the matrix into the fractures. As shown in many numerical, laboratory, and field experiments, a wide range of transfer rates occurs between the immobile matrix and mobile fractures. These arise, for example, from the different size of matrix blocks (yielding a distribution of shape factors), different porosity types, or the inhomogeneous distribution of saturations in the matrix blocks. Accurate models are hence needed that capture all the transfer rates between immobile matrix and mobile fracture domains, particularly to predict late-time recovery more reliably when the water cut is already high. In this work we propose a novel multi-rate mass transfer model for two-phase flow, which accounts for viscous dominated flow in the fracture domain and capillary flow in the matrix domain. It extends the classical (i.e., single-rate) dual-porosity model in that it allows us to simulate the wide range of transfer rates occurring in naturally fractured multi-porosity rocks. Using numerical simulations of water-flooding in naturally fractured rock masses at the grid-block scale we demonstrate that our multi-rate mass-transfer model matches the observed recovery curves more accurately compared to the classical dual-porosity model. We further discuss how tracer tests can be used to calibrate our multi-rate dual-porosity model before the water-flood commences and how our model could be employed in commercial reservoir simulation workflows.
Challenging Well-Testing Operations in High-Temperature Environments — Worldwide Experiences and Best Practices Learned
Authors: Salguero Alejandro , Almanza Edgar , Haddad Josmar 
Published: December 2011

Abstract
The oilfield industry classifies wells with bottomhole temperatures in excess of 300°F as high-temperature (HT) wellbores. Because they usually can produce large hydrocarbon volumes, all attempts to develop and produce these areas have been tried, although prospects with HT conditions present more challenging conditions. These challenges affect operational planning, equipment applications, engineering job design, and execution, and proper planning is critical to achieving job objectives.
This paper presents lessons learned and equipment applications in HT well testing environments globally, where different reservoir scenarios require modificarions to procedures, equipment configuration, and safety requirements. Each job requires consideration of ambient environmental criteria in addition to the individual operator's testing policies. Therefore, different methods for achieving job goals are needed. The lessons learned will be applicable to current scenarios in many areas and will be discussed to allow the operators to determine proper testing procedures for their HT jobs in similar conditions.
Well tests are performed using different downhole tools and procedures. A summary of these topics will include:
Operational advantages and efficiency gains New technologies to make well testing operations and evaluations more accurate Collection of downhole samples in (pressure, volume, temperature (PVT) conditions to provide the most appropriate data to be considered during future development of prospect.
New technologies are an excellent example of how technical developments and advances in the oil industry (gauges, downhole equipment, samplers, etc.) have been applied to operations in the oilfield to improve the decision-making capabilities in the oil and gas industry as well as increase well-testing evaluation success, even in extreme and challenging environments. These enhancements allow improved economic and operational efficiency as well as better safety conditions, both for the involved personnel and the environment during testing operations.
An Integrated Approach for Understanding Oil and Gas Reserves Potential in Eagle Ford Shale Formation
Authors: Fan Li , Martin Ron , Thompson John , Atwood Keith , Robinson John , Lindsay Garrett 
Published: December 2011

Abstract
Examples of an integrated approach for quantifying oil and gas production potential in different hydrocarbon windows of the Eagle Ford Shale are presented. The Eagle Ford basin is unique in that reservoir fluids range from black oil to dry gas depending on the geology, burial depth, and temperature. The main goal of this paper is to guide operators to an understanding of potential reserves and their distribution in the Eagle Ford through the use of our specialized analysis and methodology to estimate ultimate recoveries.
Data from the Eagle Ford Shale was compiled and analyzed to gain knowledge about the basin. The geology aided in indentifying "sweet spots" based on the various thermal maturation windows. Also, recent drilling and completion activities were examined in addition to the observed production from public databases. The intent was to determine curent completion practices in different parts of the Eagle Ford and also provide insight on the relationship between geologic features and production trends. A rapid asset evaluation case study is presented to demonstrate technique and workflow that uses vintage vertical well data to provide an estimate of asset value and reserves for a typical horizontal well in the Eagle Ford.
The results of the study identifies "sweet spots" of oil and gas production and indicates that 1) Eagle Ford production is related to the maturation windows, as well as structure; 2) the best wells in the Eagle Ford are in the thicker areas; 3) Austin Chalk production relates to the underlying Eagle Ford production; 4) different completions for different areas and types of hydrocarbons should be considered, and 5) data and knowledge integration is the key for rapid evaluation of asset value in the Eagle Ford Shale.
Operators can use this information and technique to help 1) better understand the uniqueness of the Eagle Ford Shale, 2) optimize their completion design and field development plan, and 3) calibrate expectations on oil and gas reserves potential under their acreage.
Single-Well SAGD: Overcoming Permeable Lean Zones and Barriers
Authors: Hocking Grant , Cavender Travis , Person John 
Published: December 2011

Abstract
Performance of conventional steam-assisted gravity drainage (SAGD) with horizontal well pairs is impacted significantly in formations with high-permeability lean zones. These lean zones rapidly halt the vertical growth of the steam chamber and spread the chamber laterally, resulting in water-loss issues and a significant impairment of the system to overcome barriers (i.e., low-permeability horizontal layers). The operating-steam pressure is lowered to reduce the water loss to the lean zone, and this in turn accentuates the impact of any barriers, thus giving rise to high steam-oil ratios (SORs) and lower production rates. A vertical single-well injector/producer was proposed that consists of six vertical propped planes installed at varying azimuths from the bottom to the top of the pay. Steam would be injected at the top of the pay, and liquids would be extracted at the bottom. The well would be operated immediately in SAGD mode (i.e., the continuous injection of steam and the continuous extraction of liquids), resulting in peak production achieved within 30 to 45 days. The system would be very efficient because of the immediate drainage available from the propped vertical planes, and also as a result of the full gravity effect on the drainage height at startup and a favorable steam-pressure gradient. Reservoir simulations show that the single-well system’s performance with high-permeability lean zones within the pay would be virtually unimpaired, both in terms of production rate and SOR. Clearly, the system’s operating pressure must be lower to reduce water loss to the lean zone; but, because of the top-down growth of the steam chamber, the permeable lean zone’s impact would be minimized. The net present value (NPV10) of the single-well SAGD system in 35-m thick Athabasca bitumen pay with a 5-m permeable lean zone was estimated to be greater than 6×NPV10 of conventional SAGD. The single-well SAGD system would be much easier to pressure balance and operate than conventional SAGD, resulting in a more robust system, provided the multi-azimuth, propped vertical planes are constructed continuously throughout the pay height.
The Benefits of Reworking Declining CBM Wells
Authors: Morad Kamal , Tavallali Mohammad 
Published: December 2011

Abstract
There are three distinguishing phases in the production life of a wet CBM well: a period of inclining gas rate due to dominance of relative permeability effects, a period of rate stabilization during which the gas rate peaks followed by the depletion phase during which gas production rate declines.
The declining gas production rate can be attributed to many factors such as: ■Declining reservoir pressure■Loss of productivity due to compaction and permeability loss■Loss of productivity due to fine migration that creates a choke skin near wellbore
While the decline in reservoir pressure is inevitable, the loss of productivity due to the choke skin and permeability loss for a declining CBM well can be remedied or slowed down through a multi-stage hydraulic refracturing. The impact of such fracturing on improving well productivity and boosting the gas production rate is investigated.
Reworking the well through refracturing could help clean up the zone near wellbore, re-activate or improve the coal network of natural fractures; lead to more effective dewatering and even create new contacts between the reservoir and formation. The area near wellbore will benefit from re-invigoration of fracture network and creation of an area of enhanced permeability.
In this study the benefit of completing a new vertical and/or horizontal CBM well with a multi-stage hydraulic fracture is examined. The production of wells with such completions are compared to typical single-stage fracturing and benefits of creating an inner zone of enhanced permeability in short-term and long term are investigated.
A numerical dual-porosity reservoir model is used to generate the CBM gas production forecasts.
Solvent Chamber Development in 3D Physical Model Experiments of Solvent Vapour Extraction Processes SVX With Various Permeabilities and Solvent Vapour Qualities
Authors: Knorr Kelvin D. , Imran Muhammad 
Published: December 2011

Abstract
Solvent vapour extraction (SVX) processes offer an attractive alternative to thermal recovery processes, being less energy intensive; and are more suitable for thinner, partially depleted reservoirs. A typical SVX process uses solvent injection to dilute the heavy oil by reducing its viscosity, allowing it to be mobilized for production. During this process the injection of hydrocarbon solvents results in partial deasphalting of the heavy oil, thus further reducing its viscosity and enhancing the process performance.
This work examined the formation and growth of solvent chambers in laterally and vertically spaced horizontal injector/producer well pairs in porous media with five different permeabilities and three different solvent vapour qualities. Consolidation of the porous media due to asphaltene precipitation was also analyzed. Thermal imaging and model excavation studies were performed to investigate the formation and growth of solvent chambers for seven different experiments conducted on a large 3D physical model apparatus.
The important findings from this study are as follows: During solvent injection, one or more solvent fingers develop between the injector and producer. The dominant solvent finger becomes a conduit that grows into a solvent chamber connected to the injection well in the upper portion of the reservoir, and develops into an oil drainage conduit connected to the production well in the lower portion of the reservoir. Solvent dispersion layers are located on the margins of both the solvent chambers and the oil drainage conduits. The location and development of these non-uniform solvent chambers and oil drainage conduits are unpredictable, and the oil drainage conduits do not grow significantly in diameter once connected to the production wellbore, limiting the wellbore inflow efficiency and conformity. Asphaltene precipitation and migration can aggravate this inflow problem, further reducing SVX process performance.
SVX performance can be improved by increasing the number and diameter of oil drainage connections between the solvent chamber and the production well, and by controlling the oil deasphalting process. This can be done by optimizing injection and production wellbore geometries, and by optimizing solvent injection rates and vapour quality.
Equipment Consideration for Continuous High-Horsepower Fracturing Operations
Authors: Yeung Tony , Deditch Scott , Schultz Darryl , Dick Graham , Eykelbosh Charles 
Published: December 2011

Abstract
In the drive to improve the economics of shale gas plays, producersare drilling more wells per pad and continually developing new techniques to maximize efficiency, reduce setup costs and optimize completion process. Through careful project planning and logistics, simultaneous 24 hour operations can be achieved. As a result, equipment is often required to operate with minimal maintenance time. The typical mobile fracturing equipment used in these operations is being operated similarly to a process plant environment and is expected to operate in excess of 18 hours per day for consecutive months, contrary to its intended design.
These operationsare primarily performed in shale formations employing stimulation treatments involvingabrasive slick waterpumped at high pressureand high flow rate.Also, the increased work cycles often lead to higher than normal erosion and fatigue frequencyinthe pumping equipment and flow lines, in comparison to conventional stimulation methods.
The paradigm shift in these fracturing operations has led to the re-evaluation of current equipment design. With data taken from a successful fracturing campaign in the Horn River Basin of Northeastern BC, this paper will discuss the challenges encountered in thisproject, the design limitation of conventional fracturing equipment and considerationsfor new equipment design which includes fuel delivery, flow line management, and equipment logistics.
Application of Wireline Stress Testing for SAGD Caprock Integrity
Authors: Mishra Vinay K. , Lywood Peter , Ayan Cosan 
Published: December 2011

Abstract
Measuring geomechanical properties of the caprock and shale gas reservoirs for enhanced oil recovery (EOR) or storage reservoirs has become an integral part of asset evaluation services. The steam-assisted gravity drainage (SAGD) process, as well as other EOR and storage applications (gas, nuclear waste, CO2), requires caprock integrity testing. Measuring in-situ stresses is an important input to caprock integrity solutions not only for the technical management of projects but also for environmental reasons.
A Wireline Formation Testing (WFT) tool is one of the commonly used techniques used for direct measurement of the minimum in-situ stress at different depths. The process is commonly called a mini-frac or micro-frac and is typically performed in an openhole wellbore. A suitable tool string includes a straddle packer arrangement, downhole pump, gamma ray sonde for depth correlation, motorized valves, and pressure gauges. To perform a stress test, an interval of the wellbore is isolated by inflating the straddle packer arrangement. The interval is then pressurized by pumping fluid until a tensile fracture is initiated. In an open hole, the fracture initiates and propagates normal to the minimum stress. Multiple injection and fall-off cycles are performed to ensure fracture growth beyond the hoop stress regime. The data is analyzed to determine fracture initiation pressure, fracture propagation, and closure pressure.
This paper describes the process of minimum in-situ stress measurement using a WFT. Lessons learnt over the years and best practices are highlighted along with their importance for proper job planning. Case studies of WFT testing including SAGD caprock stress testing from Canadian fields are presented and discussed.
Recovery Factor and Reserves Estimation in the Bakken Petroleum System (Analysis of the Antelope, Sanish and Parshall fields)
Authors: Dechongkit P. , Prasad M. 
Published: December 2011

Abstract
Recovery factor (RF) is one of the most important parameters for economic justification in the petroleum industry. The RF is calculated from the ratio between expected ultimate recovery (EUR) and original oil-in-place (OOIP). However, many uncertainties exist in OOIP estimations, mainly due to inaccurate information about reservoir drainage area. In unconventional reservoirs, the estimations of drainage area and OOIP are more complicated due to unknown factors such as fracture networks in the system, reservoir pressures, pore volumes, and in situ hydrocarbon properties.
We analyze here a case study of the Bakken Formation where the RF is still unclear and not frequently reported. RF for the Bakken formation from previous studies ranged from 0.7 – 50% (Price, 1984; Bohrer et al., 2008) derived from different approaches. In this paper, we use the material balance equation (MBE) approach to determine the deterministic (single value) and probabilistic (distribution) RF values in the Bakken Formation (the Antelope, Sanish and Parshall fields). We also perform a sensitivity analysis for the input parameters in our MBE approach.From the actual well production data, the EUR can be estimated from decline curve analysis (DCA) with knowledge of abandonment rate data. The DCA technique based on history data is used as forecast model for predicting the EUR and remaining volume. Once the RF and EUR are calculated, the OOIP value can be evaluated as the ratio between EUR and RF.
In the studied fields, RF result of the Parshall Field is highest because the produced gas-oil ratio is lower than the other two fields. From the EUR results, the high EUR area in the Antelope Field is located in the center of the field. For the Sanish and Parshall fields, high EUR areas are located in the east and west side, respectively. In addition, it appears that EUR has a direct relationship to the hydrocarbon pore volume per area (HCPV/area) distribution. For each field, the results of OOIP per well from the ratio between EUR and RF are presented, and these data can be compared with the volumetric OOIP for proper well spacing plan of future projects.
Succesful Application of Metal PCP Rechnology to Maximize Oil Recovery in SAGD Process
Authors: Arystanbay R. , Bae W. , Nguyen Huy X. , Ryou S. , Lee W. , Jang T. 
Published: December 2011

Abstract
Enhanced oil recovery methods (EOR) methods such as Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), steam drive, solvent and electric heating allow production of highly viscous crude oil at elevated operating temperatures (&gt;160°C). The choice of artificial lift technique is critical to overall well performance. Therefore it has been a challenge to find a reliable artificial lift pumping system for heavy oil thermal recovery. Available options such as beam pumps and electrical submersible pumps (ESP), which are well proven in the petroleum industry, are not particularly well suited for thermal production. Progressing Cavity Pumps (PCP), with elastomeric stator, are economic to run and have performed well in heavy oil cold production. Since their elastomers are limited in temperature (&lt;160°C), a metal PCP technology has been developed through numerous research works to meet the high temperature requirement of SAGD and other thermal recovery processes.
This paper describes the successful application of KUDU PCM VulcainTM metal PCP systems for SAGD process in Athabasca reservoir, beginning from 2007. We made analysis on production optimization in SAGD well pairs equipped with the PCM Vulcain™, which consists of a hydroformed metal stator and matching rotor utilizing special metallurgy to resist wear and maximize run life. In particular, the production with metal PCP in these wells reached the value of 200 m3/d at pump intake temperature of 200°C, performing volumetric efficiency of 82%. In general, the field results have demonstrated that the strong resistance of metal PCPs to chemical and mechanical degradation makes them a good alternative for the cold production of heavy and extra heavy oil with relatively high bottomhole temperatures and high aromatic, CO2 or H2S concentrations. This paper can be a guide for special heavy oil hot production PCP technologies to be spread and applied for EOR projects widely in the world.
Innovative Well-Completion Strategy for Challenging Heavy-Oil Wells within Mature Fields Requiring Sand Control in Colombia
Authors: Huimin Ye , Patarroyo Mauricio , Perez Moreno Carlos Alberto , Lopez Nicolas 
Published: December 2011

Abstract
Heavy-oil wells in northern South America fields are becoming increasingly more common; e.g., fields such as the Faja in Venezuela and the Llanos in Colombia are growing exponential in importance. A common thread in all of these wells is the requirement for completions that accommodate challenging environments and sand-management systems that satisfy the production goals for the field and extends the life of the reservoir. Such challenges cannot be easily met with conventional practices or downhole tools; they need to be analyzed outside the box and with a reservoir-centered mentality. A typical example of these conditions is the Moriche field in Colombia that is operated by Mansarovar Energy. When designing the sandface completion, the engineering team from Mansarovar and the selected service company used different simulations to select the sand-control strategy as well as the most appropriate sand screen to address the sand challenges of the reservoir. Different sensitivity studies were implemented using alternative completion methodologies whose results supported the decision made by the teams. This paper presents the methodology used in the selection and design of the completion for the wells in this field and will explain the different scenarios that were analyzed to select the completion methodology. We will also present the results from simulations carried out to understand the behavior of different sandface completion components during the production life of the well and the impact this new innovative approach had on the productivity of the reservoir.