bluuebunny/crossref_metadata_2025 huggingface dataset:
Steady-State Flow Behavior of CO2 Foam
Authors: Kim J. S. , Dong Y. , Rossen W. R.
Published: December 2007

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

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

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

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

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

After 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

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

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

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

This 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

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.
Impact of Acid Additives on the Rheological Properties of Viscoelastic Surfactants and Their Influence on Field Application
Authors: Al-Ghamdi AbdulWahab H. , Nasr-El-Din Hisham A. , Al-Qahtani Abdulqader. A. , Samuel Mathew M.
Published: December 2007

This paper examines a new class of viscoelastic surfactants (amphoteric) that are used to enhance sweep efficiency during acid injection. Surfactant molecules align themselves and form rod-shape micelles once the acid is spent. These micelles cause the viscosity to significantly increase, and induce viscoelastic properties to the spent acid. The enhancement in these properties depends on the micelle shape and magnitude of entanglement.

The effects of acid additives and contaminants (mainly iron (III)), on the rheological properties of these systems were examined over a wide range of parameters. Viscosity measurements were conducted on specially designed viscometers to handle very corrosive fluids. Measurements were made between 25 and 100°C, and 600 psi at various shear rates from 58 to 1,740 s−1. Acid additives included corrosion inhibitors, inhibitor aids, iron control agents, hydrogen sulfide scavengers, anti-sludge agents, and nonionic surfactants. Effects of mutual solvents and methanol on the apparent viscosity were also investigated.

It is observed that temperature, pH, shear conditions and acid additives have a profound influence on the apparent viscosity of the surfactant-acid system. The viscosity and related properties are very different from what we have observed with both natural and synthetic polymers. These properties were characterized and correlated with the type and nature of the additive used. Optimum conditions for better fluid performance in the field were derived.
Gravity Segregation and Compositional Streamline Simulation
Authors: Jessen K. , Orr F. M.
Published: December 2007

In this paper we present an approach for accurate and consistent implementation of gravity effects in compositional streamline simulation. The approach is based on an operatorsplitting technique, successfully applied in streamline simulation of black-oil models. The method is demonstrated to conserve mass. Its application adds only marginally to the overall CPU requirement. We provide a detailed description of the approach to incorporate gravity effects and demonstrate the efficiency of compositional streamline simulation, even for cases where gravity segregation plays an important role in the overall process performance. The new approach is demonstrated to be in excellent agreement with commercial FD simulators for prediction of flows in 2D vertical and multi-well 3D geometries. Finally, we outline the work required to extend the compositional streamline approach to handle three-phase flow modeling, also including gravity.
An Advanced Coiled Tubing Simulator for Calculations of Mechanical and Flow Effects; Model Advancements, and Full-Scale Verification Experiments
Authors: Yi Yunfeng , Lund Bjørnar , Aas Bjarne , He Alan Xiaojun , Rommetveit Rolv , Salem Lazaro D. , Stokka Sigmund , Bottazzi Franco
Published: December 2007

An advanced simulator for investigation and planning of coiled tubing (CT) operations has been developed. In this paper, various models pertinent to the fluid flow within the CT and in the annular space between the CT and the well wall are presented, as well as various mechanical models pertinent to the placement of the CT in the well. Some verification tests have been carried out which match well to calculations by the simulator.
Artificial Intelligence Used to Evaluate 23 Single-well Surfactant Soak Treatments
Authors: Weiss William W. , Xie Xina , Weiss Jason , Subramanium Vishu , Taylor Archie , Edens Fred
Published: December 2007

Following a series of laboratory imbibition cell experiments, field tests were conducted to determine the effectiveness of surfactant soak treatments as a single well EOR technique. The tests were conducted in the dolomite interval of the Phosphoria formation. Artificial intelligence was applied to analyze the mixed test results. The analysis suggested that the gamma ray log can be used to predict results and that a minimum amount of surfactant is required to improve production.
Simulation of Natural and Partitioning Interwell Tracers to Calculate Saturation and Swept Volumes in Oil Reservoirs
Authors: Sinha R. , Asakawa K. , Pope G. A. , Sepehrnoori K.
Published: December 2007

This paper presents several alternative ways of using partitioning interwell tracer tests (PITTs) in oil fields for the calculation of oil saturation, swept pore volume and sweep efficiency, and assesses the accuracy of such tests under a variety of reservoir conditions. The method of moments is used for the interpretation of PITTs in heterogeneous reservoirs with spatially variable residual oil saturation and extends the method to cases with mobile oil saturation. The feasibility of using partitioning tracers to estimate oil saturation at different depths in the reservoir was investigated assuming that the tracer concentrations could be measured with downhole chemical sensors or any other suitable method. The possibility of using natural organic tracers (dissolved components of the crude oil) as a low-cost alternative to injected tracers was also simulated and the method of moments was used to interpret the results for both single porosity and dual porosity reservoirs. All of these applications point to a much greater potential for the PITT technology than is commonly recognized or practiced in the oil field. The results clearly demonstrate that the method of moments is a very simple, fast and robust method to estimate oil saturation and swept pore volumes from either injected or natural partitioning tracer data.
Successful Field Pilot of In-Depth Colloidal Dispersion Gel (CDG) Technology in Daqing Oil Field
Authors: Chang Harry L. , Sui Xingguang , Xiao Long , Liu Heng , Guo Zhidong , Yao Yuming , Xiao Yuguo , Chen Gang , Song Kaoping , Mack James C.
Published: December 2007

Based on encouraging results from laboratory studies described in SPE 62610(1), a first large-scale CDG pilot test was started in the largest oil field in China, Daqing Oilfield, in May 1999. The pilot test was conducted in an area of 0.75 Km2, a double five-spot well pattern of 6 injection wells and 12 producers. The well spacing is approximately 250 meters. Up to June 2003, three chemical slugs; 0.179 pore volume (PV) of CDG slug I, followed by 0.155 PV 600 mg/l of polymer solution, and then 0.196 PV of CDG slug II. The drive water has been injected since June 2003. The pilot test indicates that with CDG injection, the reservoir permeability between injectors and producers has been adjusted and volumetric sweep improved. The water cut was reduced by 19.8%, the incremental oil production was up to 24 tons per day in the central production well B1-7-P124 during the peak production period.

The pilot test results, to date, demonstrate that CDG technology (1) can be used before, during, or after a polymer flood to effectively control the water production and maintain the high oil rate, (2) has higher incremental oil recovery with better economics than the straight polymer flooding, (3) has wide application in heterogeneous reservoirs for improving water flood efficiency and oil recovery, and (4) can reduce producing water treatment costs as compare with polymer flooding due to lower polymer production in producing wells.

This paper describes the reservoir properties in the pilot area, design of the CDG system, injection sequence of chemical systems, injection facilities, monitoring procedures, pilot test performance, and economic analysis.
Alkyl Polyglycoside Surfactants for Improved Oil Recovery
Authors: Iglauer S. , Wu Y. , Shuler P. J. , Blanco M. , Tang Y. , Goddard W. A.
Published: December 2007

Many surfactants have been evaluated for their ability to recover incremental oil; this paper focuses on alkyl polyglycosides (APG) as candidates for this IOR application. These nonionic carbohydrate-based surfactants have become in recent years a large, significant volume (over 80,000 tons/year) commercial product that sees widespread use in household and agricultural products. This laboratory study determined the characteristics of many APG surfactant formulations, in particular for their capability to create low interfacial tensions (IFT) with n-alkane hydrocarbons. Formulations explored included a wide range of alcohol and Sorbitan-based surfactants as cosurfactants with these APG surfactants. Some APG-cosurfactant combinations did exhibit low IFT values of 0.01 dyne/cm or less versus n-octane. Laboratory testing did confirm the useful properties that the IFT for these APG formulations can be largely independent of both salinity and temperature. Preliminary studies also suggest some APG products will have only modest adsorption onto kaolinite clay.
Development of Bio-surfactant Based Microbial Enhanced Oil Recovery Procedure
Authors: Maudgalya Saikrishna , McInerney Michael J. , Knapp Roy M. , Nagle David P. , Folmsbee Martha J.
Published: December 2007

The effectiveness of a bio-surfactant-based microbial enhanced oil recovery process was studied. A series of laboratory experiments showed that bio-surfactant produced by the bacterium Bacillus mojavensis JF-2 mobilized and recovered residual oil when mixed with a co-surfactant, 2,3-butanediol and partially hydrolyzed polyacrylamide (PHPA) and flooded through sand packs at waterflood residual oil saturation. Twenty to eighty percent of the residual oil was recovered depending on the bio-surfactant concentration. The recovery was linearly dependent on bio-surfactant concentration.

The injection of a viscous solution ahead of the surfactant solution and a viscous mobility buffer behind the surfactant solution increased oil recoveries compared to treatments when only the surfactant was injected. With very low bio-surfactant concentrations, 16 ppm (0.0016% by wt.), 22% of residual oil was recovered when combined with 2, 3-butanediol and PHPA. The bio-surfactant without co-surfactant and/or viscosifying polymer recovered very little residual oil (<5.0%) even at very high bio-surfactant concentrations, (12,300 ppm).

The results showed that microbially generated surface active agents were effective for enhanced oil recovery even at low concentrations (0.0016%) as long as a viscosifying agent and a low molecular weight alcohol were present.
Development of Statistical Engineering Process for Analyzing Coiled Tubing Experimental Data
Authors: Cho Joseph H. , Shah Subhash N. , Jeong Yeon-Tae
Published: December 2007

The development of coiled tubing technology and its applications have been the hot issues in the oil and gas industry for over two decades. Since improper data analysis may lead to quite a different result in the estimation of friction pressure losses and flow regime, the development of precise data processing methodology is an essential tool to provide reliable experimental analysis results. Coiled tubing experimental data are greatly influenced by mechanical system vibrations in coiled tubing reel, delayed response time, and harmonized response of sensors due to long coiled tubing flow loops. However, no reliable standardized experimental data analysis methods are currently available that take into account quantitatively the parameters affecting experimental data.

A new highly reliable statistical engineering method for analyzing coiled tubing experimental data has been developed. It is based on an enormous database gathered over a many years of coiled tubing fluid tests using 1,000 and 2,000 ft long coiled tubing with field-scale equipment. This method provides engineers and researchers statistical tools to differentiate the highly suspected outliers from the experimental data.

This paper discusses the risk of the industry method (simple average), which is widely accepted by the oil and gas industry, in removing the outliers from the experimental data. The differences in the eventual data analysis results obtained from the industry method and from the statistical engineering approach are discussed. A spe cific process of the total uncertainty analysis of experimental measurements with a 95 percent confidence estimation in precision limit and the bias limit is also presented. This statistical engineering method, developed by the Well Construction Technology Center at the University of Oklahoma, is disclosed to the public in order to enhance coiled tubing technologies and to broaden its applications.
Effects of Coiled Tubing Curvature on Drag Reduction of Polymeric Fluids
Authors: Zhou Y. , Shah S. N. , Gujar P. V.
Published: December 2007

This paper presents experimental results of the effects of coiled tubing curvature on the drag reduction behavior of polymeric fluids in turbulent flow. The experimental setup consists of a 10-ft section of ½-in. OD straight tubing and four coils of coiled tubing of the same diameter. Fluids investigated included water, guar, hydroxypropyl guar (HPG), and Xanthan fluids at various polymer concentrations. It is found that the coiled tubing curvature could reduce the drag reduction by 10 to 30% as compared with straight tubing, depending on the flow conditions. The curvature of tubing also delays the onset of drag reduction. The percentage drag reduction in coiled tubing may be improved if fluid is pumped at higher rates. The results of the present study were also verified with the previous full-scale experiments and are found to be representative of the drag reduction behavior of similar fluids under the field flow conditions.
Zonal Isolation in a U-shaped Well using Coiled Tubing and Well Tractor®
Authors: Saelensminde T , Schjott H. F. , Koldal H. M. , Skeie T. , Meberg T. O.
Published: December 2007

An 80m long retrievable "one-run" straddle assembly was successfully installed in order to shut off a gas breakthrough in the 130 degrees deviated reservoir section of a "U shape/Fish hook" sub sea oil producer in the Njord field. Coiled tubing with an internal electric line in combination with a tandem fluid driven tractor was used to convey the straddle assembly.
Development of a New Spoolable Mechanical Coiled Tubing Connector
Authors: Luft H. B. , Laun L. E. , Thov P. B.
Published: December 2007

Tube-to-tube joints in coiled tubing can be achieved by either fusion bonding or mechanical connections. A critical performance requirement of such joints is their ability to sustain plastic bending cycles that ideally, equal in number to that of the coiled tubing itself. Orbital girth welds in coiled tubing butt joints can typically achieve a low cycle bend fatigue (LCF) life in the range of 50% to 60% of the coiled tubing. Mechanical connectors of existing design and construction, have shown a considerably poorer LCF performance that is reflected by their infrequent use in coiled tubing operations.

A new spool-able mechanical connection with flush outer diameters for coiled tubing strings has been developed with comparable bend fatigue performance to that exhibited by orbital TIG girth joints. Current designs, that are based on strategic material selection and mechanical design details, range in size from 1-1/2″ to 2-7/8″. In addition to comparable or superior LCF lives, these connections overcome many of the disadvantages of welded butt joints. This paper describes the research and development, various mechanical and materials testing results and recent offshore well servicing applications undertaken with these new mechanical CT connectors.
Cuttings Transport with Aqueous Foam at Intermediate Inclined Wells
Authors: Capo Jesus , Yu Mengjiao , Miska Stefan Z. , Takach Nicholas , Ahmed Ramadan
Published: December 2007

An experimental study of cuttings transport with foam at intermediate angles has been conducted in a full-scale Low Pressure-Ambient Temperature (LPAT) flow loop at The University of Tulsa. An anionic surfactant was used in these water base foam tests at a concentration of 1% v/v. Air was used as dispersed fluid. Rheological tests were conducted to obtain flow curves for foams with 70% and 80% qualities in 2″, 3″ and 4″ pipes. A simulator was developed to predict pressure, flow velocity, specific volume expansion ratio and foam quality along the wellbore based on the volume equalized power law model.

Tests were conducted to determine the effects of inclination angle, foam quality, foam velocity and rate of penetration on cuttings transport. Results from this study show that the in situ cuttings concentration ranged, according to the inclination angles, from 4.8% to 14.6% for 45 degrees, 14.3% to 22.3% for 55 degrees and 8.5% to 25.7% for 65 degrees. It is shown in this study that the transport of cuttings (in terms of cuttings concentration) has a better performance with foams of low quality. For a given inclination angle and similar foam flow conditions, increasing the rate of penetration from 20 ft/hr to 44 ft/hr can lead to an increase in the in situ cuttings concentration of up to 7%.

A new correlation for the ratio of the cuttings bed area to the cross sectional area of the annulus as a function of dimensionless numbers (Ar, Re, Fr, Ss and θ) was developed and allows for pontential practical applicaitons. The differences between the calculated and measured values are within a range of ±17%.
An Investigation of the Effects of the Physical Properties of Coiled Tubing on Fatigue Modeling
Authors: Tipton S. M. , Behenna F. R. , Martin J. R.
Published: December 2007

A computerized database was compiled with results from over 3000 CT fatigue and mechanical tests conducted over a 10 year period. The database contains detailed information about tensile properties (yield and ultimate strengths) for individual samples that were tested to failure under constant internal pressure with specialized CT fatigue testing fixtures. This paper presents a survey of those data to assess the variability in the mechanical properties within a specific CT material grade and to investigate the effect of this variation on CT fatigue behavior.
Modeling Coiled Tubing Drag Forces – Small Factors Have a Big Impact
Authors: Terry A. R. , Mahajan Mahesh , Portman Lance
Published: December 2007

A significant limitation in the application of coiled tubing technology is the ability of the coiled tubing to push. Push may be required to move a heavy bottom hole assembly (BHA) along a highly deviated or horizontal well. Push may simply be required to push against the drag forces induced by the coiled tubing's own weight, as it is run into a well. Either way, it is often important to know how far coiled tubing can be pushed into a well, or what weight/length of BHA can be pushed to a certain depth. Accurate modeling is required to avoid a costly mis-run with coiled tubing that fails to get to the necessary depth.

Recent projects carried out offshore Brunei illustrate how critical accurate force modeling is and how small well factors can greatly affect the depth that coiled tubing can reach. This paper will also demonstrate how difficult it is to infer down hole drag conditions from surface readings unless the coiled tubing is nearing its point of maximum reach.
Cementing Through Coiled Tubing: Common Errors and Correct Procedures
Authors: Portman Lance
Published: December 2007

Cementing through coiled tubing is not a new service line. However, it remains one that has received little technical attention. In reality, there is a great deal of science behind the successful execution of such cementing operations. Failure to understand the complexities of cement placement in a well can lead to catastrophic failure, including the loss of the coiled tubing, the entire well, or both.

This paper outlines the techniques behind cementing through coiled tubing, illustrating the pitfalls and suggesting best operating procedures. The issues covered are: -

When to use cement darts. How to land cement darts. How to manage liquid freefall. How to clean up cement. What should the displacement/contaminant fluid be? What are the best nozzles? Slurry design.
Coiled Tubing Operations From Monohull Floating Production Units
Authors: Van Cann Bram , Poldervaart Leen
Published: December 2007

Given the high day rates of deepwater drilling and workover rigs, the overall drilling and well maintenance costs for subsea wells are a significant part of the total costs for deepwater field developments.

Recent drilling and completion technologies have resulted in improved reliability, higher production levels and an increase in recovery for individual wells. This has allowed for an optimization of the well system design and total well count in deepwater areas. A cost-effective access to the well and regular well maintenance during the field life are considered key issues for optimal reservoir management, which allows for accelerated production, an increase in Ultimate Recoverable Reserves (URR)and significant savings in operating costs during the field life (e.g.optimal design of process facilities).

A Floating Production and W orkover Unit (FPW U), allowing for simultaneous production and workover operations from a large monohull floater, without the need for an additional well intervention vessel has been developed (Figure 1).
High Rate Stimulation Using 2 7/8" Coiled Tubing Zonal Isolation Straddle Packer
Authors: Halvorsen Helge , Ormark Kjetil , MacCleod Alistair
Published: December 2007

This paper describes Zonal Stimulation jobs performed with coiled tubing (CT) in a chalk field in the North Sea in three wells.

The wells needed selective treatments, and through close cooperation between operator and Service Company, a new tool was developed to address all challenges regarding the wells.
Large Hydrocarbon Compositional Gradient Revealed by In-Situ Optical Spectroscopy
Authors: Fujisawa Go , Betancourt Soraya S. , Mullins Oliver C. , Torgersen Torleif , O'Keefe Michael , Terabayashi Toru , Dong Chengli , Eriksen Kåre Otto
Published: December 2007

This paper presents a case study of a North Sea appraisal well where a large vertical fluid composition variation, missed by a conventional pressure gradient analysis method, was observed in situ in real time by a new fluid composition analyzer utilizing visible near-infrared (NIR) spectroscopy. For optimal oil production, it is as vital to assess the spatial variation of fluid properties as it is to assess the spatial variation of formation properties.

Conventional wireline triple combo measurements showed the interval of interest was uniform and free from noticeable impermeable layers. A resistivity log showed an approximate oil/water contact. Wireline pressure testing identified three different pressure gradients corresponding to gas, oil, and water, all in hydraulic communication. However, the pressure testing did not indicate a gradient in hydrocarbon composition. Fluid was sampled and analyzed in real time by a wireline fluid sampling-analyzing toolstring that included the fluid composition analyzer. This tool analyzes petroleum fluid and gives concentrations for four group compositions (C1, C2−C5, C6+, and CO2), gas/oil ratio (GOR), and qualitative information regarding heavy-end content and stock-tank crude density. The analyzer showed the hydrocarbon fluid in an oilbearing zone was not vertically homogeneous but instead had a large vertical variation. The samples captured by the wireline sampling tool were sent for a laboratory compositional analysis that confirmed the variation determined by the downhole analysis. Both results identified the heterogeneity of hydrocarbon fluid in the interval.

This paper also covers briefly the measurement principle of the analyzer and discusses the impact and benefit the new technology brings. The concept of flexible fluid sampling is particularly important because it enables operators to make sampling decisions based on real-time fluid analysis results rather than a predetermined job plan.
An Application of an External Casing Perforating Completion Process in the Wilshire Devonian Field of West Texas - A Case History
Authors: Krawietz Thomas E. , Hobbs Greg , Rodgerson James L.
Published: December 2007

A new External Casing Perforating Technique (EXCP) has been utilized in the Wilshire Devonian Field in West Texas. By applying the new technology, we have been able to improve well performance, worker's safety, environmental quality and the time from rig release to first sales while holding costs within expectations. The technique was applied on all completions for the Wilshire development program in 2003.

On conventional Wilshire completions, 850' of gross pay was fracture stimulated with 2 to 3 large treatments, at high rates and pressures. The conventional technique consists of perforating on wire line, isolating each zone with bridge plugs, and selectively stimulating each zone. A conventional completion takes 3 to 4 days, with multiple trips to the location, multiple sequences of rigging up and down of service company equipment and flowing back each zone. Numerous people are required on location for the entire process.

With the EXCP system, perforating guns with isolation flappers and a hydraulic control line are attached to the outside of the casing, placed on depth and cemented in place. By applying pressure on the hydraulic control line at the surface, the guns are individually fired and the zones isolated with the flapper valves in one step. This system has allowed for more effective stimulations of up to seven individual zones within 14 hours, with immediate flow-back capability. Eliminating post-rig completion work has mostly offset the incremental EXCP cost increase. Production rates are improved while additional value is added due to a safer operation and a reduced impact on the environment.
The History and Future of China Oil and Gas
Authors: Li Dacun , Du Yuqi
Published: December 2007

China is the most populous country in the world. The booming economy with a high-percentage annual growth in GDP in the past twenty years has boosted its energy demand. Before 1993, China oil demand could be met by its own supply. After 1993, China oil demand exceeds its supply and the gap increases. As a result, more and more oil has to be imported to meet its demand. Now, about 40% of its oil consumption has to be imported, and the gap is still increasing. China surpassed Japan as the world's second-largest petroleum consumer in 2003. Even the Chinese government underestimated today's oil consumption in the 1990s. In this paper, we derive correlations based on solid oil and gas data reported in the past 20 years and then make predictions up to 2025 by using the correlations. In addition, we compare our predictions with those made by the US Energy Information Administration (EIA). Oil demand predicted by us is much higher than that by EIA, and even higher than the prediction made by EIA under the assumption of high economical growth scenario. The gas demand predicted by us is close to the reference case predicted by EIA. Gas consumption in China will increase by 500% from 2000 to 2025 while oil consumption by 200% from 2005 to 2025. A lot of oil and gas will have to be imported to meet boosting demand, creating tremendous opportunities in marketing oil and gas to China.