bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maximizing Economic Return by Minimizing or Preventing Aqueous Phase Trapping During Completion and Stimulation Operations
Authors: Davis Brian "BJ" , Wood William D. 
Published: December 2007

Abstract
Hydrocarbon exploration continues to evolve toward lower quality reservoirs, particularly in North American natural gas reservoirs. In most cases, without hydraulic fracture stimulation treatments, many wells would have no hopes of being economic plays due to inadequate production volumes relative to the costs associated with drilling the wells. Many of these reservoirs are described as "water-sensitive", but are water-sensitive due to aqueous phase trapping rather than due to clay expansion or salinity shock issues. Aqueous phase trapping is a capillary imbibition effect which has been noted in both oil and gas reservoirs, and has been observed as a particularly severe problem in reservoirs where a sub-irreducible water saturation exists. Understanding the aqueous phase trapping phenomenon is important to the oil and gas industry due to its being the driving force behind many low-permeability reservoir stimulation decisions, which are aimed at reducing the impact of aqueous phase trapping.
Diagnostic tools that utilize measured reservoir parameters are presented for use in evaluating a suspect reservoir's sensitivity to aqueous phase trapping. This paper details primary stimulation options designed to prevent production losses related to relative permeability decreases caused by aqueous trapping. Remedial treatment options where prior well treatments or production losses indicate aqueous trapping are also outlined. An example reservoir and current stimulation techniques are also described, where techniques used to reduce aqueous phase trapping problems are proving successful.
Predicting and Mitigating Erosion of Downhole Flow-Control Equipment in Water-Injector Completions
Authors: McCasland Mark , Barrilleaux Mark , Gai Huawen , Russell Ronnie , Schneider David , Luce Tom 
Published: December 2007

Abstract
Several large projects currently being developed will require high rates of water injection to sustain field life. Several operators are considering installing DownHole Flow Control (DHFC) equipment in these wells. The effects of erosion on this type of equipment could be catastrophic. Erosive effects must be accurately predicted in order to properly design equipment that mitigates them and ensures a long service life.
To do so, BP and Baker Oil Tools performed a joint test program based on a likely injection program for fields in the Gulf of Mexico. The water injection program studied required an injection rate of 45,000 bbl per day in each well. The expected field life was set at 15 years, which meant that up to 250 million bbl of water could be injected into each well. The predicted solids content was around 1 lb per 1,000 bbl, or approximately 250,000 lb over the life of the well.
This paper presents the study undertaken to predict and mitigate erosion effects under these injection conditions. Predictive studies using tools such as Computational Fluid Dynamics (CFD) software are discussed. These studies were used to change the physical geometry of the sleeves to minimize fluid velocities and erosive effects. Finally, a full-scale test of the newly designed equipment was conducted to determine the accuracy of the predictive model. The results also determined whether the configuration would minimize erosion to acceptable levels. The results of this testing are presented as well.
Commentary on the predictive capability of software modeling and analysis of the test results is included. Opinions are given on the impact this study has on the future deployment of DHFC systems in these applications.
Oilfield Environment-Induced Stress Corrosion Cracking of CRAs in Completion Brines
Authors: Stevens Richard , Ke Mingjie , Javora Paul H. , Qu Qi 
Published: December 2007

Abstract
Failures, due to stress corrosion cracking (SCC), of corrosion resistant alloy (CRA) production tubing or sand control screens have been reported in recent years. Increased use of CRA materials for downhole applications is the result of stringent requirements for high-temperature high-pressure and sweet/sour production environments, and competitive cost and availability of CRAs. Most SCC failures are related to the use of high strength CRA materials. Field observations and laboratory tests indicated that SCC of high strength CRAs was strongly related to the demanding environment in which the CRA tubulars were exposed. Oilfield environments such as the properties of associated fluids, temperatures, acid gases, types of CRA, and mechanical demands, to name a few, have been found to have a significant impact on the SCC process.
This paper presents comprehensive results from SCC evaluations of various CRA materials under different oilfield environments. The impact on SCC of different types of CRA materials for a range of temperatures, completion fluid compositions and additives was studied. SCC was also evaluated under various CO2 and CO2/H2S pressures in order to determine the stress corrosion cracking potential of CRAs. Discussion of the best practices for field applications, including on-site monitoring, control of pH and oxygen contamination, as well as other chemical additives, will be presented. These results and discussion are significant in identifying environmental factors directly related to oilfield SCC failures and in selecting best completion practices.
Developing Vertical Column Induced Gas Flotation for Floating Platforms Using Computational Fluid Dynamics
Authors: Lee Chang-Ming , Frankiewicz Ted 
Published: December 2007

Abstract
Vertical column flotation technology has been developed specifically for service on floating platforms. The technology was developed using a combination of Computational Fluid Dynamics (CFD) simulation and physical testing. The time and cost to develop the new technology was substantially reduced through the use of CFD simulation. The development program culminated in the installation and successful operation of a 10,000 barrels of water per day (BWPD) column flotation unit on a spar in the Gulf of Mexico.
CFD simulations were used to optimize the distribution of process fluids and gas bubbles in the column flotation cell and to define a strategy for skimming oil from the flotation cell while the unit was in motion on a floating platform. The result was a column flotation unit design that sweeps each volume of produced water with 150 – 300 micron gas bubbles 400 – 700 times per minute during a 4-minute contact time and permits effective oil skimming even in rough seas. Field performance data is presented for the column flotation cell that is operating successfully on a spar in the Gulf of Mexico.
New Transfer Functions for Simulation of Naturally Fractured Reservoirs with Dual Porosity Models
Authors: Sarma Pallav , Aziz Khalid 
Published: December 2007

Abstract
This paper discusses new techniques for the modeling and simulation of naturally fractured reservoirs with dual porosity models. Most of the existing dual porosity models idealize matrix-fracture interaction by assuming orthogonal fracture systems (parallelepiped matrix blocks) and pseudo-steady state flow. More importantly, a direct generalization of single-phase flow equations is used to model multi-phase flow, which can lead to significant inaccuracies in multiphase flow behavior predictions. In this work, many of these existing limitations are removed in order to arrive at a transfer function more representative of real reservoirs.
Firstly, combining the differential form of the single-phase transfer function with analytical solutions of the pressure diffusion equation, an analytical form for a shape factor for transient pressure diffusion is derived to corroborate its time dependence. Further, a pseudo-steady shape factor for rhombic fracture systems is also derived and its effect on matrix-fracture mass transfer demonstrated. Finally, a general numerical technique to calculate the shape factor for any arbitrary shape of the matrix block (i.e. non-orthogonal fractures) is proposed. This technique also accounts for both transient and pseudo-steady state pressure behavior. The results were verified against fine-grid single porosity models and were found to be in excellent agreement.
Secondly, it is shown that the current form of the transfer function used in reservoir simulators does not fully account for the main mechanisms governing multiphase flow. A complete definition of the differential form of the transfer function for two-phase flow is derived and combined with the governing equations for pressure and saturation diffusion to arrive at a modified form of the transfer function for two-phase flow. The new transfer function accurately takes into account pressure diffusion (fluid expansion) and saturation diffusion (imbibition), which are the two main mechanisms driving multiphase matrix-fracture mass transfer. New shape factors for saturation diffusion are defined. It is shown that the prediction of wetting phase imbibition using the current form of the transfer function can be quite inaccurate, which might have significant consequences from the perspective of reservoir management. Fine grid single porosity models are used to verify the validity of the new transfer function. The results from single block dual porosity models and the corresponding single porosity fine grid models were in good agreement.
Monitoring Alternating CO2 and Water Injection and Its Effect on Production in a Carbonate Reservoir Using Permanent Fiber-Optic Distributed Temperature Systems
Authors: Brown G. , Carvalho V. , Wray A. , Smith D. , Toombs M. , Pennell S. 
Published: December 2007

Abstract
This paper describes the use of fiber-optic distributed temperature systems to monitor the effect of water-alternating-gas (WAG) injection on production from several wells in a Texas carbonate reef reservoir.
Cogdell is an old reservoir re-activated by using alternating injections of water and carbon dioxide (CO2) as the tertiary recovery mechanism. Complex geology makes it necessary to monitor both injection and production over time to determine the effectiveness of the sweep.
Fiber-optic distributed temperature monitoring systems are installed on one injector and four producers, in a six-spot pattern, for continuous monitoring across the crest of the reservoir. Conventional production logging is not possible because electrical submersible pumps restrict access, and repeated injection logging required to monitor changes with the same resolution during several WAG cycles, would be impractical.
Continuous distributed temperature monitoring of the injector enabled a quantitative analysis of the injection profile. This continuous profile monitoring process identified the zone taking the majority of the injected fluid and indicated that injection into the other zones varied with the WAG cycle.
Producer monitoring allowed us to identify the flow contribution from each interval as well as changes over time. CO2 entry was also identified. This information confirmed sweep paths from the injector to the producers and provided an improved understanding of the operation of the WAG flood in the Cogdell reservoir.
The results showed fiber-optic distributed temperature monitoring provided important information for well and pattern performance analysis in wells where our prior ability to monitor response was limited or non-existent.
Alberta Multiwell Micro-Pilot Testing for CBM Properties, Enhanced Methane Recovery And CO2 Storage Potential
Authors: Mavor Matthew J. , Gunter William D. , Robinson John R. 
Published: December 2007

Abstract
The Alberta Research Council (ARC) is performing a project entitled "Sustainable Development of Coalbed Methane; A Life-Cycle Approach to Production of Fossil Energy" that is funded by an international consortium of companies. The main objectives of the project are to reduce greenhouse gas emissions by subsurface injection of CO2 into deep coalbeds and to enhance coalbed methane recovery and production rates. We have performed extensive field tests that includes efforts on two wells located near the towns of Fenn and Big Valley in Alberta that penetrated Medicine River (Mannville) coal seams. This paper presents test procedures, quantitative data measured during this effort, and the interpretation thereof. The evaluation was completed over three years ago and was based upon procedures described previously.1 These data have allowed complete characterization of the coal seam properties with new insights gained into the behavior of coal seams, the volume of natural gas that can be produced, and the volumes of CO2 that can be sequestered in this area.
The fieldwork began by reentering the Gulf Canada (now ConocoPhillips) well FBV 4A-23-36-20 (FBV 4A) well. We conducted a series of single well micro-pilot tests. We began by production and shut-in testing to obtain estimates of the reservoir pressure and permeability before CO2 injection. A CO2 injection test was followed by a shut-in test to insure that CO2 injection was possible. We then injected over 91,500 m3 of CO2 vapor in 12 separate injection cycles. Although CO2 reduced the absolute permeability, injectivity actually increased. The CO2 was allowed to soak into the coal and we returned the well to production. Post-injection testing allowed us to determine the CO2 sweep efficiency as well as the ECBM and CO2 storage potential. Fourteen months later, we injected 83,500 m3 of flue gas using underbalanced drilling equipment that was followed by a post injection-production test.
A second well (FBV 5) was drilled 487 m north of the first well. FBV 5 was cored and logged for reservoir property data. The well was then cased and completed in one Medicine River coal seam. A combination of production tests and water-injection falloff tests were conducted to determine original reservoir pressure, permeability, and gas composition. N2 injectivity tests were performed before injecting 75,483 m3 of a 53%-47% mix of N2 and CO2. The gas mixture was allowed to soak into the coal and the well was returned to production.
All of the post-injection production tests of both wells included detailed measurement of pressure and temperature conditions as well as gas composition variations vs. time. These data allowed us to determine the changes in permeability caused by the injected gas, to estimate possible hydrocarbon sweep efficiency, and possible CO2 storage volumes.
Offshore Processing Options for Oil Platforms
Authors: Bothamley Mark 
Published: December 2007

Abstract
An examination of the various processing options that have been implemented on previous (and recent) offshore oil field developments indicates a very broad range of possibilities. The spectrum ranges from:
Minimal offshore processing with all produced fluids sent to an onshore terminal (or terminals) for final processing to meet saleable product specifications, to Full processing offshore to make specification products on the offshore facility, with no further onshore processing required.
The decision as to where a given project ultimately ends up on this spectrum can have significant implications. For example:
– is the offshore platform small and simple or large and complex? – is an onshore terminal (or terminals) required for final processing or not? – does the gas export pipeline operate in multiphase, moderate pressure single phase, or high pressure dense phase? – what is the impact on project schedule and manning requirement? eg. offshore platform size and complexity, number of facilities - offshore only or both offshore and onshore? – what is the impact on subsequent future projects?
There is little published information or guidelines as to how to make the onshore/offshore processing split decision. Often it is fairly obvious based on the proximity to existing infrastructure (developed areas). In other cases, eg. new offshore regions with minimal infrastructure, it is not. In this regard, the various major offshore producing areas around the world, eg. the Gulf of Mexico (GoM), North Sea, etc., have often taken different approaches. Even in these established regions, there are significant variations in processing scheme details, from facility to facility and between operating companies.
In order to begin to address the "optimum" offshore/onshore processing split issue, it is necessary to first gain an understanding of what the options actually are. The purpose of this paper is to review the main processing options available for an offshore oil production facility, including comparisons, major factors, pro's and con's, etc. This information can serve as a basis for evaluating processing alternatives for future projects.
The Gulf of Mexico and North Sea are large, well established offshore production arenas. They can be used to provide historical context and act as points of reference. The concepts discussed are applicable to all offshore production regions.
Statoil's First Onshore Support Center: The Result of New Work Processes and Technology Developed to Exploit Real-Time Data
Authors: McCann Andrew , Omdal Svein , Nyberg Runar K. 
Published: December 2007

Abstract
Applying innovative technology and work processes to land support for offshore drilling and well operations enhances value creation chiefly through better well placement in the reservoir and more efficient operations. Over the last 5 years, new technological developments have driven an evolution in work practices towards greater integration between disciplines and over the large distances between offshore drilling operations and asset teams on land.
The Onshore Support Center (OSC) opened in December 2003 at Statoil's Mid-Norway operations office is a workplace where data and competency can meet, creating a perfect infrastructure for integrating operations. Integrated operations are a common industry goal, with widely recognized value. The center provides seamless data transfer & video-conferencing with rigs, platforms and vessels operating on Statoil's Halten/Nordland fields (via a fiber-optic cable/broadband radio), where onshore and offshore staff can share and co-visualize data and interpretations from drilling, completion and work-over operations.
The technical design of the center and the work practises used there, however, are based on a number of years of experience with increasing integration between offshore drilling operations and land-based support. To enable this evolution, a number of new technologies had to be developed, some of which have been commercialized or have led to new industry standards.
Multi-disciplinary collaboration is more natural and effective when both teams have the same data viewed at the same time in the same applications – this allows real-time data to be fully exploited. Making the drilled well data immediately available together with all offset well log and drilling data, seismic data, geological and petrophysical models opens opportunities for better drilling optimization, better controlled well correlation, near real-time formation evaluation, and therefore more optimal well placement for production. The ability of the land support team to quickly analyze the data for decision support is enhanced and reaction time to unexpected situations can be reduced.
This contribution details some of the technological developments which led to development of the Halten/Nordland OSC, showing how they have changed the way we work and affected the outcome of drilling operations.
Predictive Data Mining Techniques for Production Optimization
Authors: Zangl G. , Oberwinkler C. P. 
Published: December 2007

Abstract
This paper presents an approach, how predictive data mining models can be used to enhance and accelerate production of hydrocarbon reservoirs. The whole knowledge discovery process, combined with the automation of the data-flow bears significant potential for improving the current production practice. Predictive data mining models can perform different tasks. When they are applied automatically (i.e. scheduled after the acquisition of new data), they can reduce the workload of the knowledge workers significantly. These models act as gatekeeper, looking at the quality of data, as well as behavioral changes of wells or whole production systems.
Lessons Learned from Using Viscoelastic Surfactants in Well Stimulation
Authors: Nasr-El-Din Hisham A. , Tibbles Ray , Samuel Mathew 
Published: December 2007

Abstract
Viscoelastic surfactant systems are used in the industry for several applications. Initially, the application was focused on low friction and solids suspension (fracturing and CT- cleanout) characteristics of the fluid. In the last three years, the application of viscoelastic surfactants was extended to acid-based systems for carbonate stimulation. These surfactants have the ability to significantly increase the apparent viscosity and elastic properties of the treating fluids. This is due to the ability of surfactant monomers to associate and form rod-shaped micellar structures under certain conditions.
Viscoelastic surfactant-based acid systems have been used in Saudi Arabian fields in matrix acid stimulation, and in leak- off control acids during acid fracturing treatments. These surfactants were used to provide diversion during acidizing of vertical, long horizontal and multi-lateral wells. They were used in sour environments where hydrogen sulfide levels reached nearly 10 mol%. They were also utilized in gas wells to reduce acid leakoff, and create deep fractures in dolomitic carbonate reservoirs (250-275ºF). In addition, they were successfully employed to stimulate seawater injectors and disposal wells where the temperature was in the range of 100-120ºF.
More than 150 wells (oil, gas, water injectors and disposal wells) were treated with viscoelastic surfactant-based acid systems. The acid was placed either by bullheading, by using coiled tubing with or without a tractor. In some cases, these treatments included stages of emulsified or regular acids. All these wells responded positively to the treatment. There were no operational problems encountered during pumping these acids even when low permeability reservoirs were treated. Because these acid systems do not contain polymer, there was no need to flow back water injectors. However, the spent acid in oil and gas wells was lifted from the treated wells in a very short period of time. Finally, wells treated with surfactant-based acid systems showed sustained performance for longer times than wells treated with other acid systems.
The Value of Information: A Bayesian Real Option Approach
Authors: Galli Alain , Armstrong Margaret , G. Dias Marco Antonio 
Published: December 2007

Abstract
In this paper we propose a general methodology that applies Bayesian updating and real option theory to a probabilistic reservoir model, in order to assess the economic value of new information. The method has been tested on a gas field. The reservoir model that served as starting point for this study is described in companion paper1 at this conference. We studied four production scenarios that varied according to the size of the reserves, the city to which the gas was to be pumped and the planned level of the production plateau. Initially two wells and some seismic information were available. We show how to value the information coming from two new wells, and present guidelines for choosing between different exploitation scenarios in terms of their inherent risk.