bluuebunny/crossref_metadata_2025 huggingface dataset:
A Practical Application of Stochastic Modeling Techniques for Turbidite Reservoirs
Authors: Handyside D. D. , Karaoguz O. K. , Deskin R. H. , Mattson G. A.
Published: December 2007

A detailed study of the productivity and recovery potential for a turbidite reservoir has been completed using a practical application of stochastic modeling and reservoir simulation techniques. The objective of this study was to assess the impact of various reservoir characteristics on development considerations such as well spacing and expected production/recovery profiles.

Distributions of typical sand body dimensions were estimated from a review of core, log, seismic, and analog data. These distributions were input to a stochastic modeling program to generate multiple realizations of reservoir descriptions for a range of net/gross ratios, facies distributions, and assumed sand body geometries. An interface program was developed to minimize the gridding problems associated with conversion of stochastic model output to reservoir simulation input data. Grid data generated from this program were input directly to practically sized reservoir simulation models.

Results from the stochastic realizations and simulation models demonstrated the potential variability in connectivity and recovery profiles that may be expected for a turbidite reservoir. The reduced connectivities in the stochastic model yield significantly different production profiles and lower recoveries than would be calculated with the assumption of continuous layer-cake type models. The approach developed for this study can be used to define and improve confidence limits for production and recovery profiles from typical turbidite reservoirs with only limited well information.
Application of Nonlinear Adaptive Modeling for Rigorous Representation of Production Facilities in Reservoir Simulation
Authors: Stoisits R. F. , Batesole E. C. , Champion J. H. , Park D. H.
Published: December 2007

A nonlinear adaptive modeling technique has been used to encode a rigorous deterministic model for optimal allocation of lift gas to wells. This model was incorporated into the Kuparuk Full Field Reservoir Simulator, for the purpose of evaluating the effect of additional lift gas compression capacity on production from the Kuparuk River Field. Simulation results indicate the nonlinear adaptive model technique yields more accurate lift gas allocations than the prior allocation paradigm which was based on nonlinear regression of field data.
A Parametric Analysis of Fruitland Coalbed Methane Reservoir Producibility
Authors: Young G. B. C. , Paul G. W. , McElhiney J. E. , McBane R. A.
Published: December 2007

A "matrix" of sensitivity simulations was performed whereby combinations of key reservoir parameters and operational characteristics were evaluated. The resulting families of gas and water production curves provide an improved understanding of coalbed methane behavior and a means to assess the impact of various operational strategies.
Reservoir Evaluation of the Tangshan Coalbed Methane Prospect, Hebei Province, The People’s Republic of China
Authors: Stevens S. H. , Sheehy L. D. , Zhu Hang , Yuan Ben Heng
Published: December 2007

Based on its large reserves of gassy coals, it is likely that China has significant resources of coalbed methane. Much of this resource lies within the numerous, structurally deformed coal basins of north and northeast China. The tectonic setting and complex reservoir conditions in these basins are distinctly different from coalbed methane producing areas of the U. S. and present new challenges to coalbed methane development. A small volume of methane is currently recovered in China using horizontal boreholes and gob wells for coal mine degasification purposes, but production of coalbed methane from vertical stimulated wells has not yet been achieved.

The coalbed methane prospect described in this paper is located in the tectonically active Kaiping Basin of North China, adjacent to a major strike-slip fault. The primary Permian coal seams are 7 to 11 m thick, of high-volatile A bituminous rank, and located at depths of 700 to 1,000 m. Although the gas resource in place appears to be prospective, the large recent subsidence, extensive folding and faulting, and anisotropic stress regime in the test area underscored the need for a thorough reservoir characterization program prior to completion and production operations. Quaternary subsidence of 300-500 m may have caused the coal seams at Tangshan to be undersaturated in methane. Pre-Quatemary uplift and erosion led to degassing of the coal seams in a portion of the test area. However, geologic analysis helped to locate well sites in areas of favorable gas resource and permeability and provided preliminary estimates of important reservoir properties; reservoir testing being conducted at press time will provide accurate determination of these parameters. Measured and inferred reservoir properties were modeled using reservoir simulation to predict the coalbed methane production potential in the Tangshan test area prior to incurring the costs of a full-scale production hole. These preliminary simulations indicate that coalbed methane wells at Tangshan may have significant production potential, even at relatively low reservoir permeability (1 md).
Estimating Coalbed Gas Content and Sorption Isotherm Using Well Log Data
Authors: Hawkins J. M. , Schraufnagel R. A. , Olszewski A. J.
Published: December 2007

A new general correlation for estimating coal adsorption isotherms using log data has been developed. The "Langmuir Rank Equation," developed with the same dataset used for deriving Kim’s1 equation, provides an improved fit with the measurements. The Langmuir constants are derived from a coal rank indicator and adjusted for temperature. At elevated pressures, such as those in the San Juan basin, this approach may offer a substantial improvement in gas content estimates, as indicated in tests with a limited number of isotherms.

The new correlation, adjusted for the effect of moisture, could be used with well logs alone in estimating gas content (saturated conditions) in coalbeds where no core samples are available. Since the equation provides the entire isotherm, it could also be used in the estimation of reserves. It could also be used when quality checking isotherms. It is important to note that both log-based models (Kim and Langmuir Rank) were developed based on isotherm data, and as such, assume the coal is saturated and cannot be used to identify undersaturated coals.
Infill Drilling in the Moxa Arch: A Case History of the Frontier Formation
Authors: Cipolla C. L. , Kyte D. G.
Published: December 2007

A case history of the Moxa Arch in southwestern Wyoming details the initial development on 640 acre spacing in 1977 through 1982 and the results of subsequent infill wells drilled from 1989 to 1992. The engineering evaluation includes an integration of 3D hydraulic fracture modeling and reservoir simulation with petrophysical and geological studies.

The study indicates that the Moxa Arch Frontier Formation is very heterogeneous with permeabilities ranging from 0.001 mD to more that 0.1 mD. The productive sand thicknesses vary from less than 10 ft to over 70 ft. Effective drainage areas range from over 640 acres to less than 100 acres, with ultimate gas recoveries estimated from less than 1 BCFG to over 5 BCFG. Reservoir and hydraulic fracture modeling indicate that infill drilling on 160 acre spacing (within a portion of the Moxa Arch) would increase reserves by 68% when compared to reserves for 320 acre spacing. Results from new CO2 foam/ISP stimulations did not show significant improvement compared to early water-based fluid and sand treatments.
Postmortem Analysis: Lick Creek Meakin Sand Unit Immiscible CO2 Waterflood Project
Authors: Moffitt P. D. , Zornes D. R.
Published: December 2007

This paper gives a post mortem analysis of the Lick Creek Meakin Sand Unit (LCMSU) immiscible CO2 waterflood project. The project was initiated in 1976 to increase oil recovery from the thin, heavy oil sand. A reservoir simulation study run prior to the project indicated an immiscible CO2 waterflood would recover twice as much oil as a conventional waterflood (oil recovery of 16 percent OOIP for an immiscible CO2 waterflood versus 8 percent OOIP for a conventional waterflood). The project was scheduled to be developed in four stages: 1) cycle all wells with CO2, 2) continuous CO2 injection into the unit injection wells, 3) alternate CO2 and water injection in the injection wells, and 4) water injection only into the injection wells; however, CO2 and water injection in the unit ended prematurely due to the precipitous drop in oil prices in 1986. Channeling of the injected CO2 and water in the immiscible CO2 waterflood project has been a major area of concern. During the course of CO2 injection, a foam treatment and 15 gelled polymer treatments were applied in the unit to increase diversion of the injected fluids and improve sweep efficiency.

Incremental oil recovery from the project, over that of primary recovery, has been estimated to be 1.75 MM STB [0.278 MM m3] of oil to October 1, 1990 (11.1 percent OOIP), compared to an initial projection of 16 percent OOIP incremental oil recovery. The lower than projected oil recovery was due to channeling of the injected CO2 and water in the reservoir and also due to the premature termination of the project due to low oil prices. The results of the 15 gelled polymer treatments conducted to reduce channeling have been favorable overall with incremental oil recovery from the gelled polymer treatments estimated to be 114,700 STB [18,240 m3] from a total of 76,800 active pounds [34,850 kg] of polymer injected or 1.49 STB of oil recovered per pound [0.52 m3/kg] of polymer injected. The use of tracers in identifying high permeability channels was instrumental in the success of these treatments.
Effects of Gravity and Viscous Crossflow on Hydrocarbon Miscible Flood Performance in Heterogeneous Reservoirs
Authors: Pande K. K.
Published: December 2007

Injected solvent composition is a key parameter in the design of hydrocarbon miscible floods. Economic optimization of a field flood requires consideration of the effect of solvent composition on flood performance at the reservoir-scale. In this study, a compositional simulation approach was used to study the effects of permeability heterogeneity, fluid crossflow, and phase behavior on displacement performance in two-dimensional, finegrid (x-z) cross-sections. Results of secondary and tertiary solvent flood simulations in various rock property fields indicate that floods with solvent enrichment at or below that required for development of multicontact miscibility in one-dimensional flow can perform as well or better than floods with richer solvents. A significant change to the current practice of solvent enrichment selection is suggested based on analysis of the simulation results.
Equation of State Characterization and Miscibility Development in a Multiple Phase Hydrocarbon System
Authors: Okuyiga M. O.
Published: December 2007

This paper presents the characterization of an equation of state (EOS) for some heavy oils from the West Sak field on the Alaskan North Slope. The EOS description was needed for evaluating an enhanced oil recovery (EOR) scheme for the field. Various gases ranging from carbon dioxide to enriched hydrocarbon gases have been evaluated in the laboratory as potential solvents.

The interaction of the oils with these solvents is dominated by liquid-liquid phase behavior at reservoir conditions. It is further complicated by the occurrence of a third hydrocarbon phase at certain solvent concentrations. These phenomena are quite Important to the development of miscibility. The EOS developed accurately predicts these interactions.

The dissolution of gases in West Sak oil causes significant reduction in viscosity. A corresponding states viscosity correlation was successfully used to predict the viscosity changes accompanying solvent dissolving in the oil.

Compositional simulations of slim tube displacements involving both two and three hydrocarbon phases have been successfully carried out, while elucidating the mechanisms important for miscibility development.
An Evolutionary Approach to Slim-Hole Drilling, Evaluation, and Completion
Authors: Worrall R. N. , van Luijk J. M. , Hough R. B. , Rettberg A. W. , Makohl Friedhelm
Published: December 2007

Shell and Eastman Teleco have developed a Slim Hole Drilling system appropriate for hole sizes less than 6 1/4″ in diameter. Since the project was started in 1987 the system has been used in 46 wells. Nine wells contained 4 1/8″ hole, one down to 5382 meters. Overall progress per day no longer decreases in smaller hole sizes enabling the total well design to be downsized. Cost reduction of up to a quarter (or more in some cases) are thus possible. The smaller scale of operations reduces environmental impact. Extensions such as horizontal, high pressure / high temperature, and floating drilling are underway. Complementary evaluation and completion technology allows Oil Companies to downsize production wells, potentially reducing field (re)development costs. There remain significant opportunities for the service industry to develop complementary "Slim" rigs, equipment, and services.
Designing Wells for Subsidence in the Greater Ekofisk Area
Authors: Bickiey M. C. , Curry W. E.
Published: December 2007

Well deformations in the Ekofisk Field are attributable to reservoir compaction and the related seabed subsidence. In 1989, unusual techniques/tools such as reduced strength cement, intentional leaks and casing elongation tools were utilized to combat the effects of compaction/subsidence and thus prolong well life.
Surface Monitoring of Downhole Vibrations: Russian, European, and American Approaches
Authors: Dubinsky V. S. H. , Henneuse H. P. , Kirkman M. A.
Published: December 2007

Surface monitoring of downhole vibrations, a promising way to improve drilling efficiency, has been the subject of growing recent interest. While the history of vibration monitoring in Russia has been similar to that of Europe, with an initial focus on the effects of lithology, it was subsequently developed into a solution for problems relating to turbodrilling efficiency, the common approach to drilling in Russia. Elf Aquitaine, in France, commenced work for real-time lithological recognition from surface vibrations in the 1960s; drilling optimization evolved as a further application using their Dynametre. ARCO Oil and Gas Company developed a very similar technology to Elf, focussed initially on reducing premature fatigue failures in the drillstring and bit.

All three approaches are now being synergistically combined through cooperation in this area, and contain many identical elements, both in theory and practice, which highlight the basic common physics of these measurements. Field examples of each approach, and practical applications of this technology are presented. A combination of all of the above techniques will improve the contribution made by surface vibration monitoring to drilling optimization.
Formate Brines: New Solutions to Deep Slim-Hole Drilling Fluid Design Problems
Authors: Downs J. D.
Published: December 2007

Advanced slim hole drilling technologies being introduced for creating cost-effective deep exploration and development wells require a totally new type of drilling fluid that minimises parasitic pressure losses while maintaining effective suspension properties at high temperatures.

A set of high-density organic brine systems based on formate salts has been designed to meet these, and other performance criteria visualised as necessary for an ideal deep slim hole drilling fluid. High-temperature-high-pressure rheology and fluid loss experiments, in both conventional laboratory equipment and IFP's fluid test loop, have confirmed that the new brine formulations have good thermal stability to at least 150°C.

The results from many detailed rheological measurements on these formulations will be fed into advanced fluid hydraulic models to validate the original design concept for minimising parasitic pressure losses in deep slim hole wells by using low-viscosity brine-based drilling fluid systems.
New Approach to High-Density Cement Slurries for Cementing High-Pressure, High-Temperature Wells
Authors: Johnston N. C. , Senese Maurizio
Published: December 2007

A new technique has been developed for densified slurry cementing operations employing a new mix-water dispersible weighting agent. This approach has overcome many logistical, quality control and slurry design problems encountered with conventional dry-blended weighting agents.
Field Evaluation of a Novel Inhibitive Water-Based Drilling Fluid for Tertiary Shales
Authors: Reid P. I. , Minton R. C. , Twynam Allan
Published: December 2007

Laboratory tests showed that tetra-potassium pyrophosphate (TKPP or K4P207) gave levels of shale inhibition well beyond that obtained with equivalent concentrations of potassium chloride. A detailed evaluation indicated that stable mud formulations could be prepared which were considerably more inhibitive than other mud systems currently available. Inhibition even approached the level of that observed with oil based mud with some shale types.

Two North Sea field trials were selected to evaluate the field performance of these phosphate muds. In both cases there were extensive formations of very reactive Tertiary shale which were known to be unstable when drilled using conventional water based muds. Each location also provided good offset data from similar wells drilled with both oil based and conventional water based fluids. This allowed the performance and economics of the phosphate muds to be thoroughly assessed.

In both field trials the highly inhibitive nature of the new systems was confirmed when the shale sections remained open and stable for extended periods. However, in both wells the overall performance of the system was disappointing because of severe problems caused by very firm cuttings adhering to the stabilisers. This "accretion" resulted in slow, tight trips to surface, gave problems with blocked flowlines and a rapid buildup of drill solids, which consequentially required higher than planned mud dilution.

The cause of the accretion problem has been investigated and explained. Work is now underway to find a practical solution.
Innovative Slim-Hole Completions
Authors: Ross B. R. , Faure A. M. , Kitsios E. E. , Oosterling Peter , Zettle R. S.
Published: December 2007

The successful development of slim-hole drilling and evaluation technologies has created business opportunities that are contingent on the development of complementary slim-hole well completion technology. The monobore well completion philosophy is presented. Potential applications and limitations of slim-hole completions are discussed. Areas requiring further development are identified.
Experience with Temporarily Sealing Leaking Tubing Annuli with Extended-Life Polymer Gel Plugs in the Greater Ekofisk Area
Authors: Urdahl Hans , Kettl F. C. , Crossley E. G. , Williams T. A.
Published: December 2007

Extended-life polymer gel plugs have met rigorous requirements as a sealant for restoring a barrier in the tubing annulus when tubing-annulus leakage has occurred. These requirements include urgency to restore annulus integrity, dynamic placement in unbalanced well conditions, and ease of removal without milling the tubing. Very attractive economic benefits have resulted.
Through-Tubing Remedial Treatments Using a Novel Epoxy Resin System
Authors: Gunningham M. C. , van Paassen A. S. W. , Samuel A. J.
Published: December 2007

A new formulation epoxy resin system has been developed, with a solvent system that is compatible with high-expansion elastomers. The versatile epoxy resin system can thus be used with through- tubing straddle packers to treat intervals selectively. The system can be used for sand consolidation, water shut-off and cement repairs. This paper describes the laboratory testing of the new system, various applications of the novel epoxy resin and a case history of the first field trial. Laboratory testing of the system has shown that for sand consolidation the system gives 80-90% return permeability while resulting in increases in unconfined compressive strength of typically 50-70 bar. The system can also be used for shut-off purposes, reducing permeability to water by 99%. Gas shut-off may be less effective. The new resin system produces consolidated sand packs with low moduli of elasticity, which may allow them to survive pressure fluctuations better than more rigid formations. The compatibility of the system with high-expansion straddle packers has been field-proven.
A New 3D Hydraulic Fracture Simulator That Implicitly Computes the Fracture Boundary Movements
Authors: Choate P. R.
Published: December 2007

A new 3D hydraulic-fracturing simulator, GEOFRAC, is described that implicitly couples the solution of the fracture boundary movements with that of the fluid pressure and fracture width profiles over the fracture face. Results obtained with the new simulator are shown to be strictly consistent with its underlying assumptions for a simple case - a condition that may not always be true for the results of commercially available simulators. This difference in the results is shown to relate to the improved numerical procedures that have been implemented in the new simulator.
Application of a Pressure Analysis Expert System During Exploration Drilling
Authors: Tangen Kjell , Baleix J-M.
Published: December 2007

DAPEX (Detection of Abnormal Pressure while Drilling EXpert system) is an expert system which monitors and analyses drilling parameters in real-time during drilling. Its purpose is to perform a comprehensive pressure analysis based on data available from several sources, including surface measurements, downhole measurements (MWD) and predicted geological data. The system identifies abnormal pressure conditions as well as diagnoses their origins.
Tracer Analyses in Stratified Reservoirs (Determination of the Permeabilities Profile)
Authors: Bedrikovetsky Pavel
Published: December 2007

In this paper we discuss the problem of the reservoir characterisation from the tracer test data. Oil-water rates and tracer concentration on the productional wells are available. The problem is to determine the permeability profile.

The new pseudorised equations for the displacement of oil by water with tracer in heterogeneous stratified reservoir are derived. Analyses of the tracer wave propagation into the layer cake reservoir during the waterflooding was given on the basis of analytical solution of the direct displacement problem. Exact analytical solution of the inverse reservoir characterisation problem provides explicit formulae for the profile of permeability.

The method developed was applied for the interpretation of pilot test on gas injection in the Vuktyl field (Russia, Timan-Pechora region). The results obtained from the tracer analyses data fits well with the data of logging and core analyses.
Clair Discovery: Evaluation of Natural Fracturation in a Horizontal Well Drilled in the Basement and Producing from Overlying Sediments
Authors: Fait Urban , Guerin Gwenaël , Retail Phillipe , Evans Martin
Published: December 2007

An extensive fracture analysis was performed in a highly deviated to horizontal well drilled in the basement of the Clair discovery, U.K.C.S. Fracturation is the key factor for the well productivity since the oil is produced through fractures connecting the horizontal drain to the overlying and adjacent oil bearing Old Red sandstones of Devonian age.

The main objectives of this study was first to determine and characterize the fracturation pattern along the well, and then to establish the relationship between the fracturation pattern and the possible producing zones identified from the production log interpretation.

The fracturation methodology which was adopted for the fracturation analysis is described in the paper and is based on the descriptions of cores and on the interpretation of openhole logs comprising classical logs, full waveform acoustic log, borehole televiewer log and production log The high resolution televiewer information was calibrated to fracture characteristics determined from the seven cores taken in the Basement and extended to the scale of the well by use of the Full Waveform acoustic log information.

The fracture system in the basement is characterized by several patterns of different scales. The major fractured intervals, spaced between 100 and 150 m, were interpreted to be interacting with a secondary fracturation pattern more closely spaced around 15 to 40 m. These fractured intervals correlate well with the producing zones identified from the production log interpretation.

To complete the fracturation analysis, a comparison between the determined fractured intervals and drilling parameters (ROP, downhole torque and gas shows) was done. It is found that at least two of these parameters respond as the same time to fractures during drilling.

It is believed that detection of the major fracture zones can be possible during the drilling phase of any well drilled in the basement.

The application of the described methodology is highly recommended on future wells with similar objectives.
Successful Safety Management: Five Years of Effort Pays Off
Authors: Grundt H. J. , Lindeberg Reidar , Nygård Morten
Published: December 2007

Statoil was established as Norway's state oil company in 1972. Following a period of exploration and project development, the company became operator of several onshore and offshore facilities in the mid ‘80s, through friendly take-overs and exercise of options.

The paper describes the initiative taken by corporate management in 1987 to harmonize different safety cultures and to improve Statoil's Safety Management System to facilitate effective risk control. A six point plan for improvement and other safety measures of a motivating nature has now been successfully implemented. Additional measures are now being proposed to ensure continued reduction of occupational accidents and overall risk exposure.
Pressure Transient Analysis of a Shallow Horizontal Gas Well: Test Objectives, Design, Procedure, Interpretation, and Application of Results
Authors: Cochrane J. F. , Reynolds K. C.
Published: December 2007

In 1990 Texaco Exploration and Production Inc. drilled and completed the first horizontal wells ever drilled in the Gulf of Mexico. The wells, East Cameron Block 278 "B" Platform Wells B-12 and B-14, are about 195 nautical miles southwest of New Orleans, Louisiana in 173 feet of water. The wells are completed in a shallow gas sand at a depth of about 1700 feet TVDSS.

The B-14 well was tested in April 1991. The primary objective of the test was to obtain data for a reservoir simulation study to compare the ultimate recovery of a horizontal and a vertical well in the same reservoir. Other objectives were to use the simulation model to optimize production rates; to characterize inflow performance; to evaluate the slotted liner/prepack gravel pack completion; and to use the data to optimize the length of the horizontal section in future wells. To meet the test objectives, five high resolution quartz memory pressure gauges were placed throughout 380 feet of the horizontal section.

Based on the analysis of the test data the following conclusions were reached: the horizontal well will recover nearly twice as much gas as a conventional well completed in the same reservoir; the optimum rate for each well is about 20 MMSCFD; the reservoir is contributing flow along the entire length of the horizontal section; and that gas flowed outside the prepack gravel pack completion during the test. Test data also indicate that the common assumptions of infinite conductivity and uniform flux are not valid for this well.

This paper describes the test objectives, design, operational aspects, alternatives evaluated, test data, interpretation and application of results, and the ultimate recovery of a horizontal well versus a conventional well.
Crawford: The First U.K. Field Abandonment
Authors: Dall R. N. , Gilliver R. E. , Sclater Raymond
Published: December 2007

In 1991 Crawford became the first UK North Sea field to be abandoned. Novel approaches were employed both in the design of the development and in the methods used to abandon the wells and facilities. These, together with detailed planning and early involvement with the UK authorities, contributed to the success of the abandonment operations which were completed under budget and without injury. Most of the equipment recovered was in suitable condition for re-use.

Well abandonment and subsea facilities removal operations were conducted concurrently. The Yatzy, a dynamically positioned (DP) semi submersible drilling rig, was used to abandon the wells. The use of a dynamically positioned rig resulted in flexibility in the sequencing of operations and time and cost savings on rig moves. It was able to work very closely with the dive support vessel (DSV) Stena Constructor used to recover the subsea facilities and to assist with re-entering the subsea wells.
Continued Development, Reservoir Management and Reservoir Modelling Have Increased Proven Developed Oil Reserves by Over 35% in the Marginal Scapa Field
Authors: Ellison R. L. , Simlote V. N. , Ko R. S.
Published: December 2007

The understanding of reservoir performance, reservoir heterogeneity, distribution of oil in place and continued data gathering has resulted in a reservoir description and predictive model for use in evaluation of reservoir response to waterflood processes and recovery efficiency for this marginal offshore field.

The vital data for assessing the reservoir flow characteristics were obtained from annual production log surveys, requiring a floating rig at the template and continuous pressure recordings obtained from the permanent downhole gauges in template and platform producers.

An active data gathering program during a prolonged shut down period provided valuable information for the field history match.

Original oil in place (OOIP) in the Scapa field is estimated as 248 million STB. The field had produced about 40 million STB or sixteen percent OOIP through 1991.

The ongoing field development drilling has further provided the extent of the oil accumulation and improved understanding of the geology. This paper assesses the value of the routine reservoir management data acquisition programs which results in improved understanding of reservoir production behaviour resulting in increased proven developed oil reserves by thirty-five percent in this marginal offshore field.
Remediation of the Contaminated Ocean Floor Around Offshore Platforms in the Gulf of Mexico
Authors: Fang C. S. , Tao Kaiqin , Lin Jong-Her
Published: December 2007

The previous effort of cleaning the contaminated ocean floor around offshore platforms in the Gulf of Mexico has been evaluated and an improved cleaning process is presented based on the preliminary study which uses laboratory experimental data, field data and computer calculations. The improved cleaning process includes filtration, air flotation and carbon adsorption operations. The improved process can reduce the organic compounds returning to the ocean from 841 ppm to approximately 5 ppm.
The Effect of pH on the Adsorption and Transport of Phosphonate Scale Inhibitor Through Porous Media
Authors: Sorbie K. S. , Yuan Ming Dong , Chen Ping , Todd A. C. , Wat R. M. S.
Published: December 2007

This paper presents results and analysis for several cycles of low concentration phosphonate (DETPMP) inhibitor floods in highly reproducible sandpacks. The central objective of this work is to present a detailed study of the effects of solution pH on the adsorption behaviour of phosphonate inhibitor. Displacements at constant near neutral and low pH conditions and in pH gradients have been carried out The latter type of flood is analysed in terms of coupled adsorption where the adsorption isotherm is a function of both inhibitor concentration and [H+] (or pH). The main finding is that phosphonate inhibitor adsorption level is higher at lower pH values. Non-equilibrium adsorption is also evident in the low pH floods. The floods are simulated and analysed using a non-equilibrium, coupled adsorption numerical model which reproduced most of the main features observed in the experiments. The modelling also leads to some novel interpretations of the experimental results which are then tested by further experiments. In order to put this study in a practical context, some further sensitivities, to calcium ion concentartion and pH on high concentration phosphonate adsorption, are also presented in this work. Again, it is shown that the pH and [Ca++] effects exert a coupled influence on phosphonate adsorption.
Ion Chromatography Tracer Experiments During Drilling
Authors: Hall Christopher , Hughes T. L.
Published: December 2007

We describe field tests carried out to show that salt tracers injected into the mud at the surface during drilling can be used to measure the extent of hydrodynamic dispersion during well-bore circulation. The results of one test using lithium bromide are described in detail, together with the procedures for tracer injection, sampling of return mud, and chemical analysis by ion chromatography. Test data are analysed in terms of residence time theory, and the residence time density function, cumulative distribution function and washout function are computed. Results suggest that circulation is well-mixed and is close to plug flow. The observed washout function is compared with the predictions of several simple models. The anion was completely recovered in the filtrate but cation losses were observed which are attributed to ion exchange with clay solids during circulation. In tests with salt mixtures, cation losses reflect the affinity of ions for clay cation exchange sites.
Physical/Chemical Studies on the Surface Interactions of Bentonite With Polymeric Dispersing Agents
Authors: Rabaioli M. R. , Miano Fausto , Lockhart T. P. , Burrafato Giovanni
Published: December 2007

This paper describes an experimental investigation of the effect of various commercial anionic polyelectrolyte thinners on the stability of bentonite dispersions contaminated by mono and divalent salts. Combined adsorption and electrophoresis studies lead to the definition of a model for the mechanism of interaction between the polyelectrolyte and clay. The data presented suggest that, with the exception of FeCr-lignosulphonate, the thinners adsorb preferentially onto the edges of the clay particles. In the case of FeCr-lignosulphonate significant adsorption onto the faces of the bentonite is attributed to the bridging effect of the polyvalent metal ions. The different adsorption mechanisms have consequences for the amount of polyelectrolyte required to deflocculate and stabilise the dispersions. Flocculation tests confirm that polymers adsorbing selectively on the "edge" sites are more effective in stabilising the dispersion against flocculation than those which adsorb less selectively onto the bentonite surface. Interestingly, the rheological properties of bentonite dispersions improve even where the thinner produces a scarce deflocculation effect At least two mechanisms appear to describe the rheology-reducing properties of the thinners studied. Thinners like FeCr-lignosulphonate, which do not deflocculate the dispersions, can be distinguished from others such as the polyacrylates, which are true dispersing agents for bentonite in the presence of high electrolyte concentration, by means of scaling analysis of the rheological results.
Surfactants: Additives to Improve the Performance Properties of Cements
Authors: Cowan K. M. , Eoff Larry
Published: December 2007

ABSTRACT*

The primary focus of this paper is on the use of surface active agents (surfactants) to modify the properties of Portland cements for well cementing operations. Surfactants, as abroad class of compounds, have been largely ignored as additives to improve the performance of cements for well applications. Use of surface active agents in cements is primarily within two main functions – retarding agents and dispersing agents. The surface active agents currently used for these two functions do not provide the benefits that other types of surfactants can provide.

The types of surfactants discussed here are distinctly different in functional groups, physical characteristics (molecular weights), solution properties and effect on cement properties than presently used surface active agents. The potential widespread benefit from the use of these materials in cement formulations can be seen. Some of the benefits which can be realized by incorporating the types of surfactants studied in this work are: (1) improved interfacial sealing between cement and pipe, (2) less shrinkage of the cement during setting and hardening, (3) savings on cement materials and (4) improved cement properties at lower cost.
Asphaltene Precipitation: A Need for a Broader View
Authors: Deo M. D. , Hanson F. V.
Published: December 2007

Asphaltene content of an ultra-heavy oil was compared to the asphaltene contents of residual fractions obtained after supercritical extraction of the oil with propane. The asphaltene contents of the residual fractions were found to be significantly greater than the asphaltene content of the original oil even after prorating the values to weight percent of the original oil. This increase was believed to be due to the depletion of lighter cosolubilizing compounds from the oil. The H/C atomic ratio of the residual fractions was lower compared to the original oil, indicating that the ratio of polar to nonpolar compounds may also be important from precipitation considerations. Saturate and aromatic compounds were preferentially extracted and the ratio of asphaltenes to resins increased in the residual fractions relative to the original oil. The data demonstrated that the asphaltenes in the original oil were not the only compounds susceptible to precipitation and that a broader view of the precipitable material is necessary in order to understand the precipitation problem in oil reservoirs.
Field-Related Mathematical Model to Predict and Reduce Reservoir Souring
Authors: Sunde Egil , Thorstenson Tore , Torsvik Terje , Vaag J. E. , Espedal M. S.
Published: December 2007

A mathematical model for reservoir souring caused by growth of sulfate reducing bacteria (SRB) in the reservoir has been developed. The model is a 1D numerical transport model based on conservation equations and includes bacterial growth rates, the effect of nutrients, water mixing, transport and adsorption of H2S in the reservoir formation.

Two basic concepts for microbial H2S production were tested using the model: H2S production in the mixing zone between formation water and injection water (mixing zone model), and H2S production due to SRB growth in a biofilm in the reservoir rock close to the injection well (biofilm model). In both cases H2S adsorption by reservoir rock was considered.

Field data obtained from three oil producing wells on the Gullfaks field correlated with H2S production profiles obtained using the biofilm model, but could not be explained by the mixing model.

The biofilm model implies that H2S production is correlated to the quality of the injection water, especially nitrogen (N) and phosphorous (P). The use of chemicals (containing N and P) in injection water treatment should therefore be reduced to a minimum.
A Reservoir Simulation Study of a Cooperative Waterflood
Authors: Herbert William F. , Wattenbarger Robert A.
Published: December 2007

A small pressure maintenance project was surrounded by a larger project with higher producing allowables. Cooperative water producing allowables. Cooperative water injection wells had been selected along the leaseline to provide for the displacement of equal areas across the lease boundary. A cooperative agreement had been made which governed the injection and producing rates of both parties in the vicinity of the leaseline.

A reservoir simulation was undertaken to determine if the cooperative agreement and operating policies could be changed to the additional benefit of both leases. The waterflood was modeled with a two-dimensional three-phase unsteady-state reservoir simulator. A number of possible operating conditions were simulated to determine their effect on leaseline oil migration, and oil and water production. From the series of runs, an understanding of the mechanics of the waterflood was developed which would not have been possible without the quantitative results of reservoir simulation. The fillup, productivity, and three-phase flow effects productivity, and three-phase flow effects were all very important. Recommendations were made which should make the project more profitable to both leases. profitable to both leases. Three cases are presented to illustrate the application of reservoir simulation to the problem. The comparison of cases shows that problem. The comparison of cases shows that it is possible to select leaseline injection and production rates which will further reduce oil migration and still result in better oil and water producing characteristics for both leases.

Introduction

This paper discusses a reservoir simulation study of the problem of leaseline migration in a cooperative waterflood. The usual approach is for the operators to enter into an agreement which sets limits on water injection rates and pressures. To reduce oil migration, they agree to produce leaseline wells at low rates, below their producing capacities. The cooperative agreements usually apply to all leaseline wells regardless of their locations or producing characteristics.

In this particular waterflood, an agreement of this type had been in effect for the first 18 months of the waterflood. The primary purpose of the simulation study was primary purpose of the simulation study was to see if the cooperative agreement could be altered to the additional benefit of both leases.
Effective History Matching: The Application of Advanced Software Techniques to the History-Matching Process
Authors: Parish R. G. , Calderbank V. J. , Watkins A. J. , Muggeridge A. H. , Goode A. T. , Robinson P. R.
Published: December 2007

The modelling and history matching of hydrocarbon reservoirs is widely accepted to be a challenging task requiring considerable expertise.

This paper describes the application of advanced statistical and knowledge based techniques to the development of a software tool aimed at making the history matching process more efficient and effective. We conclude that, provided such systems are used as decision support tools for the reservoir engineer, they can significantly enhance the ability of the human expert to obtain a satisfactory history match.
Reservoir Characterization of a Fractured Reservoir Using Automatic History Matching
Authors: Smith R. A. W. , Tan T. B.
Published: December 2007

The Subject oil reservoir will not be identified to preserve requests of confidentiality. Oil production from the Subject field is primarily from a highly fractured and faulted formation. The initial reservoir pressure is several thousand psi above the bubble point pressure. Pressure surveys after one year of production mdicated a recharge source. The source of the pressure support could be from (a) the matrix volume assuming a dual porosity system, (b) an aqwfer composite system or (c) an oil filled composite system with a low permeability outer zone. Matching the pressure data with any of these reservoir descriptions would establish the most plausible reservoir characterization. However, to carry out the task of varying the parameters of each reservoir description until a satisfactory match is obtained for that particular description would be extremely onerous and time consuming if done manually.

To solve this problem, a three-dimensional three-phase reservoir simulator with automatic history matching capability was used. The simulator was able to obtain the best possible match for each reservoir description by regressmg on the porosity and directional permeability parameters. The competing models were then compared and the model that matched the historical pressure observations as well as conforming to the established parameters of the geological model was determined to be the true model.

The results of the above analysis indicated that the dual porosity system did not provide an acceptable fit of the pressure data and thus it was rejected. Excellent matches were obtained with the aquifer composite model and the oil filled composite model. The parameters of the aquifer composite model that were necessary to obtain a match did not conform with other geological and pressure transient analysis mformatlon. However the oil filled composite model parameters were in close agreement with the well test interpretation model and the geological features of the reservoir. This was the model that was fmally accepted. Thus automatic history matching was a valuable tool in the reservoir characterization of the Subject Reservoir.
The Modeling of Flow in Heterogeneous Reservoirs with Voronoi Grid
Authors: Palagi C. L. , Ballin P. R. , Aziz Khalid
Published: December 2007

The flow rate at each interface between gridblocks is a function of an "effective" permeability of the connection. The upscaling procedure consists of evaluating average connection permeabilities based on a smaller scale description of the reservoir. While several procedures have been reported in the literature to scale up permeability values for Cartesian grids, these procedures have not been extended to flexible grids. The Voronoi grid allows the specification of each gridpoint independently; therefore, it provides flexibility to represent wells and reservoir heterogeneities.

This paper describes an upscaling procedure of permeability values at the interface of Voronoi gridblocks. The description of the heterogeneity, e.g., a stochastic image, is independent of the grid geometry. The power law average of the permeability values at each connection is computed automatically by the computer code. The optimum value of the power law coefficient is determined by comparing fine and coarse grid results for selected images and well configurations.

Several well configurations were investigated with different grid geometries (Cartesian, hexagonal and locally refined hexagonal) using the same description of the reservoir. The optimum value of the power law coefficient was almost the same for all combinations of grid geometries and well configurations (between -0.5 and 0). Also several stochastically generated images of the reservoir, all honoring the same data, were analyzed. Again the optimum value of the power law coefficient was almost the same for all images. The hexagonal grid yields more robust results because each gridblock has more neighbors than the Cartesian grid. The use of local grid refinement around wells reduces the overall error.
Eighth SPE Comparative Solution Project: Gridding Techniques in Reservoir Simulation
Authors: Quandalle Philippe
Published: December 2007

This paper reports the results of a Comparative Solution Project (CSP) which compares different flexible gridding techniques now available in some reservoir simulators. This CSP was performed by five participants and the problem posed is a 3D simulation of oil production associated with gas injection in a four layer reservoir. The participants were asked to provide two sets of results with the same simulator : the first set corresponding to a simulation run with a regular 10x10x4 Cartesian grid, and a second set corresponding to a simulation run with a flexible grid optimised to have as few grid nodes as possible.

Two different types of flexible grid have been used by the participants, Control Volume grids (CVG) [1,2], and Locally Refined Cartesian grids (LRCG) [3,4], These grids are shown in the paper.

With flexible grids, all participants could reduce the number of grid nodes by a factor four or more, while keeping the simulation results close to those obtained with the regular 10x10x4 Cartesian grid.