bluuebunny/crossref_metadata_2025_split huggingface dataset:
The First Coiled Tubing Deployed ESP in the Gulf of Mexico
Authors: Keck Richard G. , Robertson S. W. , Butler D. J. , Bumbaugh D. B. 
Published: December 2007

Abstract
In February 2003 BP installed the first coiled-tubing deployed electric submersible pump in the Gulf of Mexico. The Grand Isle 40 F-1 well had been producing for several years with 27/8" jointed tubing, and the two previous electric submersible pumps lasted 16 and 30 months. Once the ESP failed, the well was produced at a much lower rate using gas lift for another 11 months or more until the ESP replacement could be scheduled and executed. The project discussed in this paper utilized a rig to replace the entire 9,700’ of production tubing with a 2-3/8" coil string that had the ESP at the bottom. The benefits of this deployment method include a reduction in the down time between pump change outs and a reduction in project cost. When the ESP fails, a liftboat and coiled tubing unit can be mobilized sooner, and at a lower cost, than a rig. The added cost of this first coil installation will pay out with the first rig-less pump replacement.
The goals of the paper are to document this successful case study and to illustrate the value that CT-ESP has in the Gulf of Mexico offshore operating environment. We start with a history of CT-ESP's installed elsewhere, and then discuss our well and why it was a candidate for a coil-deployed ESP. We then discuss our rationale for running the 2-3/8" diameter coil instead of other available sizes, and why we decided to run the cable external to the production string. Pre-job planning, regulatory issues, HS&E and equipment testing will also be addressed. Additionally, key elements of the operation, and the procedure to terminate and test the coil while running in the hole are presented. The conclusion will detail some of the lessons learned during the operation and the overall project economics.
Coiled Tubing and Wireline Intervention for Well Abandonment
Authors: Kirby S. , Skelly G. , Gordon D. , Sheed S. 
Published: December 2007

Abstract
This paper discusses the systematic approach adopted by BP Exploration to achieve its goal of safely abandoning the wells on a major North Sea platform. Having determined the abandonment methodology, an integrated team, comprising oil company engineers and key service company personnel developed processes and procedures to reach the objective. These included advances in coiled tubing rig-up procedures and the use of Technical Limit to capture learning. This approach facilitated the timely and cost effective abandonment of 24 wells in a safe and environmentally friendly manner and in achieving world-class performance.
Steady-State Flow Behavior of CO2 Foam
Authors: Kim J. S. , Dong Y. , Rossen W. R. 
Published: December 2007

Abstract
Foams can improve oil recovery by reducing gas mobility and the effects of reservoir heterogeneity. Numerous studies report that foam flow in porous media comprises two regimes. In the "high-quality regime," pressure gradient is nearly independent of gas superficial velocity. In the "low-quality regime," pressure gradient is nearly independent of liquid superficial velocity. Previous published data from CO2 foam studies lie either in the high- or low-quality regime, but no single study shows both regimes. Delineating the two foam-flow regimes is essential to modeling and predicting the behavior of CO2 foam in petroleum applications.
Experiments were performed with a sand-pack and a fired Berea and Boise sandstone cores at a back-pressure of 1500 or 2000 psig, above and below the critical temperature of CO2. The data from the sand-pack, Berea and Boise-sandstone experiments at room temperature do not show the two conventional foam-flow regimes. Instead, these experiments find a third regime evidently related to the low-quality regime. This same behavior was observed in the sand-pack above the critical temperature of CO2. In this new regime, pressure gradient decreases with increasing liquid superficial velocity at constant gas superficial velocity. The Boise-sandstone experiment above the critical temperature of CO2 did find the two conventional foam-flow regimes, however. No single experimental factor appears to explain the difference in results.
Earlier theoretical work of Hirasaki and Lawson and de Vries and Wit can partially explain the flow regime seen in our study. A model combining a bundle-of-tubes approach with the effective-viscosity function of Hirasaki and Lawson predicts the behavior in this new regime.
Improved Oil Recovery in Under-Saturated Reservoirs Using the US-WAG Process
Authors: Ning S. X. , McGuire P. L. 
Published: December 2007

Abstract
This paper describes the improved oil recovery mechanism in under-saturated reservoirs using an immiscible water-alternating-gas (IWAG) process. When lean gas is injected into an under-saturated reservoir, incremental oil recovery is achieved through oil viscosity reduction, oil swelling, and improved sweep efficiency. Oil viscosity reduction is found to be the dominant mechanism in improving oil recovery from severely under-saturated reservoirs.
The Kuparuk River formation at Milne Point field on the North Slope of Alaska contains highly under-saturated oil with a bubble point pressure of 1875 psi and an initial reservoir pressure of 3500 psi. When lean gas is injected into the reservoir, oil viscosity can be reduced by as much as 43% and oil formation volume factor increased by 4%. These changes in oil properties lead to a calculated incremental oil recovery of 6–9% of original oil-in-place (OOIP).
Results from compositional reservoir simulation as well as laboratory measurements are presented in this paper. The theoretical study is supported by actual field production data from the Milne Point field. Reservoir management strategy has changed significantly based on this technical study and detailed economic analysis. The once on-going MWAG process has been replaced with a US-WAG (Under-Saturated Water-Alternating-Gas) process, which substantially improves the economics of the field.
The US-WAG process is also applicable in any severely under-saturated reservoirs where miscible injection might be hard to achieve, such as the heavy oil reservoirs on the North Slope of Alaska. Significant improvements in oil recovery can be achieved through reduction in oil viscosity by injection of separator gas into the reservoir.
Low Salinity Oil Recovery – Log-Inject-Log
Authors: Webb K. J. , Black C. J. J. , Al-Ajeel H. 
Published: December 2007

Abstract
Many laboratory coreflood studies have shown increased oil recovery is achieved by waterflooding using low salinity water, compared with injection of seawater or high salinity produced water. The reasons for this improved oil recovery are thought to be due to effective wettability changes and / or controlled removal of clay constituents. This paper describes a log-inject-log field test, designed to identify whether this phenomenon could be observed within the near well region of a reservoir. The log-inject-log test was meticulously designed and executed, to ensure that flow rates were maintained at low rates, and that cross flow was minimised, to ensure that the results were representative of bulk reservoir waterflood displacement. A producing well was selected for the test to ensure that all saturation changes occurred under stringently controlled test conditions and that the results would not be affected by previous high rate water injection. 10–15 ‘pore volumes’ of high salinity brine, were injected into the ‘volume of interest’, to obtain a baseline residual oil saturation. This was followed by sequences of more dilute brine followed by high salinity brine for calibration purposes. Multiple log passes were conducted during injection of each brine. At least three further passes were run to ensure that a stable saturation value had been established after injection of each brine. Extensive water sampling was conducted to confirm brine salinities and increase confidence in the quantitative saturation results. The results were in line with previous laboratory tests from other fields, and showed 25–50% reduction in residual oil saturation when waterflooding with low salinity brine.
Single Well Alkaline-Surfactant Injectivity Improvement Test in the Big Sinking Field
Authors: Miller Bernie J. , Pitts Malcolm J. , Dowling Phillip , Wilson Dan 
Published: December 2007

Abstract
The Big Sinking Field is a mature waterflood in the Appalachian Basin of Eastern Kentucky. The 100 plus million barrel (15.9 million m3) field is primarily a shallow tight oil reservoir at 1,150 feet (350 m). A primary constraint to production is the ability to inject fluid into the reservoir. This project was an effort to increase injectivity by injecting an alkali-surfactant solution to reduce the residual oil saturation with a resultant increase in effective permeability to water. Oil is mobilized away from the injection well bore where a substantial portion of the injection pressure is lost by reducing capillary forces that trap oil. A new well was drilled and cored, and a laboratory program performed prior to field implementation. A variety of mixtures of alkali and surfactant reduced the interfacial tension between oil and water to 0.001 dyne/cm from 23.6 dyne/cm. Injection of a Na2CO3 plus ORS-62HF alkaline-surfactant solution increased the relative water permeability by 425% and a NaOH plus AX-210-6 alkaline-surfactant solution increased the effective water permeability by 310%. Subsequent fresh water injection resulted in a loss of effective permeability to water to 155% times the original waterflood base for the Na2CO3 plus ORS-62HF solution. The NaOH plus AX-210-6 coreflood maintained injectivity at 325% with subsequent water injection. In September 2003, injectivity testing began with injection of fresh water into a newly completed well to establish initial injection rate. A 1,500 barrel (238 m3) injection of NaOH plus ORS-162HF alkaline-surfactant solution followed. Return of fresh water injection showed an increase in fresh water injection from 41 to 75 barrels per day (6.5 to 11.9 m3).
Alkaline-Polymer Flooding of the David Pool, Lloydminster Alberta
Authors: Pitts M. J. , Wyatt K. , Surkalo H. 
Published: December 2007

Abstract
An alkaline-polymer flood was implemented in the center of the David Field (now called Black Creek) outside of Lloydminster, Alberta, Canada. Simultaneously, waterfloods were conducted in the same reservoir to the north, west, and south of the chemical flood area. The alkaline-polymer area produced 5.7% OOIP by primary production from 1969 to 1978. Waterflood production from 1978 to June 1987 produced an additional 25.5% OOIP, for a total primary plus waterflood oil recovery of 31.2% OOIP. Average primary plus waterflood production of the north, west, and south waterflood areas as of September 2001 is 51.9% OOIP with an average oil cut of 2% in the three-waterflood areas. Alkali plus polymer co-injection was initiated in the David Field during June 1987. The project has an irregular pattern consisting of seven injection wells and eighteen production wells on twenty acre spacing. Water followed the tapered polymer slug. Oil cut in the alkaline-polymer flood area is 1.5%. Alkaline-polymer injection produced an incremental 21.1% OOIP. Primary, waterflood, and alkaline-polymer flood oil production is 73.0% OOIP. Total project cost is C$7,284,000 for a chemical mixing plant with water softening, drilling of fourteen new wells, purchase of injected chemicals, and engineering and design expenses. Incremental chemical cost per produced barrel of oil is C$1.41/bbl or US$0.99/bbl. Total cost per incremental barrel is C$3.53 or US$2.48. Selection of injected chemicals was based on a laboratory design process. Fluid-fluid screening, linear corefloods, and radial corefloods were performed to develop the most economically and technically viable injected solution. Surfactant was eliminated from the injected solution based on coreflood data, capillary theory, and Taber number calculations.
Because fourteen new wells were drilled just prior to alkaline-polymer solution injection and the project was started when the oil cut was 40%, performance is difficult to interpret the alkaline-polymer flood in a conventional manner. This paper provides an interpretive analysis of the David Pool alkaline-polymer flood performance.
An Optimization Methodology of Alkaline-Surfactant-Polymer Flooding Processes Using Field Scale Numerical Simulation and Multiple Surrogates
Authors: Zerpa Luis E. , Queipo Nestor V. , Salager Jean-Louis 
Published: December 2007

AbstractAfter conventional waterflood processes the residual oil in the reservoir remains as a discontinuous phase in the form of oil drops trapped by capillary forces and is likely to be around 70% of the original oil in place (OOIP). The EOR method so-called alkaline-surfactant-polymer (ASP) flooding has been proved to be effective in reducing the oil residual saturation in laboratory experiments and field projects through reduction of interfacial tension and mobility ratio between oil and water phases.A critical step to make ASP floodings more effective is to find the optimal values of design variables that will maximize a given performance measure (e.g. net present value, cumulative oil recovery) considering a heterogeneous and multiphase petroleum reservoir. Previously reported works using reservoir numerical simulation have been limited to sensitivity analyses at core and field scale levels because the formal optimization problem includes computationally expensive objective function evaluations (field scale numerical simulation).The proposed methodology estimates the optimal values for a set of design variables (slug size and concentration of the chemical agents) to maximize the cumulative oil recovery from a heterogeneous and multiphase petroleum reservoir subject to an ASP flooding. The surrogate-based optimization approach has been shown to be useful in the optimization of computationally expensive simulation-based models in the aerospace, automotive, and oil industries. In this work we have extended this idea along two directions: i) using multiple surrogates for optimization, and ii) incorporating an adaptive weighted average model of the individual surrogates.The proposed approach involves the coupled execution of a global optimization algorithm and fast surrogates (i.e. based on Polynomial Regression, Kriging, and a Weighted Average Model) constructed from field scale numerical simulation data. The global optimization program implement the DIRECT algorithm and the reservoir numerical simulations are conducted using the UTCHEM program from the University of Texas at Austin.The effectiveness and efficiency of the proposed methodology is demonstrated using a well-known field scale case study.
Reaction Kinetics of the Uptake of Chromium(III) Acetate by Polyacrylamide
Authors: Jain R. , McCool C. S. , Green D. W. , Willhite G. P. , Michnick M. J. 
Published: December 2007

Abstract
Gelled polymer treatments applied in injection and production wells are used to alter fluid flow in oil reservoirs so that oil production is increased and water production is decreased. A common gel used in field treatments is made by crosslinking partially hydrolyzed polyacrylamide (HPAM) with chromium acetate. The initial step of the crosslink is the uptake of chromium acetate by a carboxyl group on the HPAM. The kinetics of the uptake reaction was studied as functions of the concentrations of chromium, HPAM and hydrogen ion. The data were regressed to derive a rate expression for the disappearance of unreacted Cr(III) in the gelant.
A Successful Experience for Fiber Optic and Water Shut Off on Horizontal Wells with Slotted Liner Completion in an Extra Heavy Oil Field
Authors: Foucault H. , Poilleux D. , Djurisic A. , Slikas M. , Strand J. , Silva R. 
Published: December 2007

Abstract
Identifying the water producing section of a horizontal well completed with a slotted liner in Extra Heavy Oil (EHO) proves by itself to be a challenge. Being able to isolate that same interval and selectively injecting a water shut off treatment is even more challenging. To properly isolate the selected section, the annulars (open hole / slotted liner) above and below must be sealed; those annular may or may not be filled with formation sand.
This paper describes the water shut off experience in the Sincor Field in an EHO environment. Initially, the water producing interval was identified through the use of temperature measurements performed with a fiber optic. Then the zone to be treated was isolated using cement rings placed in the annulus, combined with the use of cement retainers. Following the isolation of the zone, a gel solution that polymerizes in situ followed by a tail slurry of micro-matrix cement were selectively injected. The idea behind the treatment is to create an impermeable barrier to the unwanted water production coming from the end of the well. The well treated had an initial water cut of 85%, and after the treatment the water cut was decreased to almost zero and the oil production boosted up by a 250%, compared to hydrated production period. Additionally, the final well productivity index (PI) indicates that the treatment effectively treated only the selected section.
In horizontal wells and EHO environment, the fiber optic tool proved to be a simple and reliable technology to assess the water production zone along the drain. An associated water shut off operation using cement and gel may then be implemented to reduce the water cut and to increase significantly the oil production rate.
Effect of Drainage Height and Grain Size on the Convective Dispersion in the Vapex Process: Experimental Study
Authors: Ali Yazdani J. , Maini Brij B. 
Published: December 2007

Abstract
Interest in the vapor extraction (Vapex) process for heavy oil and bitumen recovery has considerably grown as a viable and environmentally friendly alternative to the currently used thermal methods. The potential for success of Vapex process is even more attractive in some scenarios that preclude the thermal methods. Presence of overlying gas cap and/or bottom water aquifer, thin pay zones, low thermal conductivity, high water saturation, unacceptable heat losses to overburden and underburden formations etc., are some of the limitations with the thermal techniques, which can be potentially overcome by vapor extraction implementation. However, predicted low production rates by previous researchers for field application of Vapex technique remain a serious barrier to commercial applications of the process. The scale-up methods that have been used by previous workers for translating the laboratory results to field predictions were primarily based on the reservoir transmissibility. An analytical model developed by Butler and Mokrys1 showed that the oil rate should be proportional to the square root of reservoir transmissibility. The effect of convective dispersion between solvent and virgin heavy oil in porous media were ignored in developing this model.
The main objective of this work is to develop an improved scale-up method for the Vapex process using physical model experiments carried out in models of different sizes. In this paper we report the results of a new series of experiments that extend the previously reported results of Karmaker and Maini2 to a significantly wider range of model heights. These new experiments employed a new design of slice type physical models that places the sand-pack in the annulus formed by two cylindrical pipes. Combining the new results with the previous data of Karmaker and Maini2, we show that the transmissibility based scaling up method seriously under-predicts the results at larger scales. This observation suggests that much higher rates can be expected in the field implementation of the Vapex process.
A new correlation has also been proposed for scaling up the experimental data to the real field cases. It indicates the height dependency of the convective dispersion contribution, which can be the dominant mass-transfer mechanism for the process, to be higher order than previously postulated. Experimental results from this work show that the stabilized rate is a function of drainage height to the power of 1.1 to 1.3, instead of the square root functionality of the Butler and Mokrys2 model.
Improved Fracture Stimulation Revitalizes the Western 31S Stevens Oil Zone, Elk Hills Field, California
Authors: Agiddi David , Hernandez Helver 
Published: December 2007

AbstractThis paper reviews the fracture stimulation improvement achieved over the recent three years with extensive field redevelopment and workover against the backdrop of fracture development of the Western 31S (W31S) Stevens Oil Zone in the central California Elk Hills field since 1998.The W31S is one of the major Stevens reservoirs within the huge 31S anticline structure. It has low to moderate permeability distribution and severe layering throughout the pay interval. From experience, significant stimulation is often required to overcome near-wellbore formation damage and generate favorable economics to sustain a redevelopment drilling program. Perforation, matrix acidizing and fracture stimulation have been performed on cased hole completions with varying degrees of success.Hydraulic fracture stimulation introduced in the W31S much later, proved to be very successful in improving well productivity but has enormous operational and production problems associated with it that required process improvement. Such problems ranged from in-situ stress variations that may lead to pre-mature screen-out, proppant diversion with cement integrity issues common with older wellbores, proppant flow back problems, effective vertical coverage of the target pay intervals, gel residue and the consequent damage to fracture conductivity. While acid treatments were sometimes used to remove the created damage on a few of the W31S wells, several of the wells have serious limitations on well performance that would be difficult and costly to remove.Significant gains in production have been observed following successful fracture treatment optimization. The use of a unique small-chain polymer, high performance viscoelastic fracturing fluid (HPF) lead to higher per well productivity and minimized post-frac production problems compared to past jobs with conventional fracture treatment containing borate cross-linked guar polymer and encapsulated oxidizing breakers.
Anomalous Acid Reaction Rates in Carbonate Reservoir Rocks
Authors: Taylor K. C. , Nasr-El-Din H. A. , Mehta S. 
Published: December 2007

Abstract
It is generally assumed that limestone reservoir rocks will react much more rapidly with acid than dolomite reservoir rocks. This work is the first to show this assumption to be false in some cases, due to mineral impurities commonly found in these rocks. Trace amounts of clay impurities in limestone were found to reduce the acid dissolution rate by nearly an order of magnitude, to make the acid reactivity of these rocks similar to fully dolomitized rock. A rotating disk instrument was used to measure dissolution rates of reservoir rock from a deep, dolomitic gas reservoir in Saudi Arabia (275 °F, 7,500 psi). More than 60 experiments were made at temperatures of 23 and 85 °C and HCl concentrations of 1.0 M (3.6 wt%). Eight distinctly different rock types that varied in composition from 0 to 100% dolomite were used in this study. In addition, the mineralogy of each rock disk was examined before and after each rotating disk experiment with an Environmental Scanning Electron Microscope (ESEM) using secondary and backscattered electron imaging and energy dispersive X-ray (EDS) spectroscopy. Acid reactivity was correlated with the detailed mineralogy of the reservoir rock. It was also shown that bulk anhydrite in the rock samples was converted to anhydrite fines by the acid, a potential source of formation damage.