bluuebunny/crossref_metadata_2025_split huggingface dataset:
Permeability Scaling in a Numerical Coning Model
Authors: Dutta V.K. , Arnold M.D. 
Published: December 2007

Abstract
A method is described for simulating coning into a wellbore using a numerical simulation model. The method allows the wellbore cells to be considerably larger than the actual wellbore. This makes coning studies feasible using an implicit pressure-explicit saturation type model with a reasonable time step. This capability is achieved by scaling the horizontal-vertical permeability ratios to give the proper vertical potential drop.

Introduction
Water coning into producing oil wells is often a problem in oil reservoirs underlain by bottom water and occurs due to potential gradients established around the well bore by oil production. If vertical permeability exists, this difference permeability exists, this difference in flow potential raises mobile water into the well bore. Gravity forces caused by the density difference between fluids tend to counteract the dynamic and imbibition capillary pressure gradients. When the combined pressure gradients. When the combined effect of dynamic forces and capillary pressure exceeds the gravitational pressure exceeds the gravitational force, the water advances toward the well and eventually breaks through in it.
A two-dimensional, two-phase mathematical model was developed in radial coordinates for this study to simulate water coning in petroleum reservoirs. The first step in developing this model consisted of deriving a partial differential equation suitable for describing the pressure distribution in a two-dimensional pressure distribution in a two-dimensional system. The derivation of the equation allowed the simultaneous flow of two slightly compressible phases. These partial differential equations were partial differential equations were then expressed as finite difference equations with respect to both the space and time variables. The entire model was discretized in two dimensions in order to accommodate the finite difference form of the equations. The simulator provides for variable size rectangular blocks on the face of a vertical section (See Figure 1).
Oil Rim Development Using Horizontal Wells Off Shore Abu Dhabi
Authors: Al Kaioumi Q. M. , Nassar O. , Al Hendi A. 
Published: December 2007

ABSTRACT
A study has been initiated to determine the best development scheme to recover oil and gas from two oil rim reservoirs off shore Abu Dhabi utilizing horizontal wells. One pilot horizontal well has already been drilled in the lower reservoir and few more are planned.
Due to uncertainties in the fluid contacts and reservoir characteristics, a vertical pilot hole had to be drilled and cored to decide on the optimum location of the horizontal hole.
A detailed core study was conducted to study the main rock types and lithofacies of this reservoir and a sector model was constructed to study the effect of different reservoir parameters on the performance of the horizontal well.
PVT data from the gas cap and the oil rim will be used to construct an EOS that will be used in the full field compositional model.
The results from this model and the performance of the pilot horizontal wells along with ongoing detailed geological study will help in determining the optimum development plan for these reservoirs.
Aerated Mud Drilling Experience In Abu Dhabi
Authors: Mokhalalati Talal , Reiley Richard , Neidhardt Dietmar 
Published: December 2007

ABSTRACT
Aerated mud is now a proven technique for drilling lost circulation zones in ADCO's fields. Severe lost circulation problems encountered while drilling surface aquifer formations were traditionally cured by using oil to lighten water based mud. Aerated drilling is one method that eliminates any environmental impact of discharging oil to the desert. As a pilot, four wells were drilled in Abu Dhabi Onshore field utilising aerated mud. All proved to be operationally successful achieving the goal of drilling without using crude oil to lighten the mud. The extra cost of the air compressors was offset by eliminating crude oil and waste treatment cost. Air drilling time was reduced 16 % by the 4th well, but further improvement in bit hydraulics is required to increase penetration rates. The original air package design was to deliver 1500 SCFM of air at 1350 psi. A booster to increase the air discharge pressure to 1900 psi was employed for the last three wells. This increased the hydraulic energy delivered to the bit. Using greater air compression capacity with optimised bit nozzles played the key role in improving bottom hole cleaning and increasing the rate of penetration.
Drilling Fluid Design to Prevent Formation Damage in High Permeability Quartz Arenite Sandstones
Authors: Smith P. S. , Browne S. V. , Heinz T. J. , Wise W. V. 
Published: December 2007

Abstract
Quartz arenites are very clean quartz sandstones with unusually high permeabilities for any given porosity. This is attributed to the presence of large, clean pores which are often well connected. These large pores are susceptible to drilling damage, mainly from the invasion of solids. This paper presents both laboratory and field data on the development of drilling fluids to minimise damage in quartz arenites. The required changes in field mud engineering practices, to achieve improved well performance, are discussed. Field experiences are presented, including the impact of the modified mud systems and engineering practices on the resulting skin factors.
Seismic Porosity Mapping in the Ekofisk Field Using a New Form of Collocated Cokriging
Authors: Doyen P. M. , den Boer L. D. , Pillet W. R. 
Published: December 2007

Abstract
An important practical problem in the geosciences is the integration of seismic attribute information in subsurface mapping applications. The aim is to utilize a more densely sampled secondary variable such as seismic impedance to guide the interpolation of a related primary variable such as porosity. The collocated cokriging technique was recently introduced to facilitate the integration process. Here we propose a simplified implementation of collocated cokriging based on a Bayesian updating rule. We demonstrate that the cokriging estimate at one point can be obtained by direct updating of the kriging estimate with the collocated secondary data. The linear update only requires knowledge of the kriging variance and the coefficients) of correlation between primary and secondary variables. No cokriging system need be solved and no reference to spatial cross-covariances is required. The new form of collocated cokriging is applied to predict the lateral variations of porosity in a reservoir layer of the Ekofisk Field, Norwegian North Sea. A cokriged porosity map is obtained by combining zone average porosity data at more than one hundred wells and acoustic impedance information extracted from a 3-D seismic survey. Utilization of the seismic information yields a more detailed and reliable image of the porosity distribution along the flanks of the producing structure.
A Decline Analysis Technique Incorporating Corrections for Total Fluid Rate Changes
Authors: Masoner L. O. 
Published: December 2007

Abstract
Decline analysis for secondary or tertiary oil recovery processes typically assumes that the total reservoir fluid rate (referred to here as the processing rate) remains constant. This same assumption inherently remains when extrapolating oil decline curves into the future. In reality, many surface operational activities, injector and producer stimulations, pump changes, and recovery processes alter the processing rate. The literature offers superposition and rate normalization techniques to handle these situations for oil decline related to pressure depletion. This paper offers an alternative approach that permits history matching rate changes on the familiar rate-time plot and providing a means to forecast future oil and non-oil production performance under different processing rate strategies. This paper (1) develops the theoretical basis for the approach, (2) presents examples for both water and CO2 flooding, in-fill drilling, and stimulations, (3) imparts how the approach can improve the accuracy and flexibility of decline analysis, and (4) outlines procedures for implementation of the technique for increasing flood performance understanding.
The approach presented assumes that the recovery process and drainage volume remain essentially unchanged and that these mechanisms are not impacted by changes to the processing rate. The remaining oil reserves and an associated initial oil decline rate are estimated for the special case in which the processing rate remains constant and only the fluid cuts change; each fraction of oil production decline is offset by an increase in the water or non-oil fraction. At specific time intervals (monthly), the oil rate and decline are modified based on the actual or forecasted processing rate, the oil cut maturity, and the remaining reserves. The initial oil decline and associated remaining reserves are solved for iteratively until achieving a suitable history match.
The technique helps to identify pseudo-steady state flow periods when decline analysis techniques are valid while avoiding transition periods when decline analysis is not applicable. It readily distinguishes incremental from accelerated oil responses, being uniquely suited for cases where a recovery process change, operating practices, or workover activity results in a change to the processing rate. This technique can forecast both oil and water production or oil and non-oil phase production when producing more than 2 phases.
Innovative Data Acquisition : West of Shetlands
Authors: Cowper D.R. , Jackson P. , Storm R.W. , Halford F.R. , Stuart G. 
Published: December 2007

Abstract
This paper describes how fast track reservoir appraisal has been achieved in prospects to the West of Shetlands through an integrated and innovative programme of data acquisition. The approach addressed the key uncertainties in evaluating the prospect by using a combination of the logging, seismic and core techniques. These methods have resulted in significant cost and time savings by reducing core acquisition and minimising the need for Drill Stem Tests.

Introduction

Background.
The West of Shetland province lies approximately 120km west of the Shetland Islands (Figure 1). Following discovery in 1992, a fast track development programme was undertaken in order for the province to sustain BP's maturing North Sea portfolio.
The prospects are set in deep water (200–1000 metres) and are exposed to difficult met ocean conditions. Drilling costs typically constitute over 30% of the project budget and any reduction in well numbers and rig time resulting from an efficient reservoir appraisal would heavily impact the project economics.
Consequently, the requirement for early oil delivery combined with the expensive drilling environment drove the development of a rapid reservoir appraisal programme.

Reservoir Appraisal
Traditional reservoir appraisal has taken a sequential approach to addressing the key uncertainties in reservoir prospectivity. As a result the appraisal of North Sea prospects has taken on average nine years from discovery to delivery of first oil. By using an integrated approach which has required the simultaneous planning of field development and infrastructure, it will have been possible for BP and partner Shell to reduce this time to 4 years and dramatically increase the profitability of the project.
To assist the integrated approach, reservoir appraisal strategy had to be geared to constraining the most influential reservoir uncertainties as early as possible. The aim of this paper is to illustrate how this was achieved by a holistic and innovative programme of data acquisition.

Key Uncertainties
The Parametric Method provides a means of illustrating the influence of key uncertainties on reservoir prospectivity. Uncertain parameters are identified and their base, upside and downside cases estimated. P. 63
Field Experience with a New On-Line Oil-in-Water Monitor
Authors: Holweg P. A. M. , Huizer W. 
Published: December 2007

Abstract
On-line measurement of the oil concentration in effluent water streams from oil production operations is highly desirable for improved control of both the water quality and the production process. However, a severe difficulty in arriving at suitable on-line instrumentation is the high robustness which is needed for oil industry applications. In particular, the presence of suspended solids in the produced water should not influence the oil concentration measurement. Further, the use of solvents must be prevented.
To meet these specific oil industry requirements a new oil-in-water monitor has been developed, which uses an alternative measurement principle, namely a combination of sample conditioning and light scattering This patented operating principle allows a good discrimination between dispersed oil and suspended solids The accuracy of the instrument is typically 2 mg/1 of dispersed oil in water in the 0-200 mg/1 measurement range.
Field tests with a commercial prototype instrument have been conducted at several oil production locations The tests demonstrated that the measurement principle is sufficiently robust A good discrimination between dispersed oil and suspended solids was achieved and no fouling problems were encountered Also it was demonstrated that the availability of on-line information is highly valuable for the improvement of production operations
The Effect of Temperature on Caustic Displacement of Crude Oil
Authors: Cooper Ronald J. 
Published: December 2007

Abstract
Laboratory studies were carried out to determine the effect that temperature has on the waterflood recovery of oil from a consolidated core with the use of a weak sodium hydroxide solution as the flooding agent. The reduction in interfacial tension of several crude oil - caustic systems was investigated to determine a caustic solution that would reduce the interfacial tension to a minimal value. The resulting 0.20 weight percent sodium hydroxide solution was thereby determined and used as the caustic waterflooding agent throughout the displacement tests.
Displacement tests were conducted at temperatures of 130 degrees, 160 degrees and 190 degrees F with both distilled water and the weak sodium hydroxide solution as the flooding agent. The tests indicated that the addition of the sodium hydroxide to the displacing fluid increased the waterflood recovery over that obtained with water at all temperatures investigated.

Introduction
Improved recovery of oil by secondary recovery techniques is becoming most important as the cost of finding new reserves has continued to increase. The low gravity, viscous crude oil reservoirs typically exhibit low recoveries and offer potential for new methods of secondary recovery. Waterflooding of viscous oil reservoirs has been avoided in the past as the displacement mechanism under such reservoir conditions has rarely been economically successful. Cyclic steam stimulation has proven to be successful in some areas; however, the ultimate recovery anticipated is commonly 10 to 25 percent of the original oil in place which leaves considerable potential for other recovery methods.
The addition of sodium hydroxide in small amounts to the water used in waterflood operations has been proposed as a potential process for improving recovery in secondary process for improving recovery in secondary recovery operations. The effect of reducing oil - water interfacial tension has been indicated to improve recovery from waterflood operations. Laboratory work by Emery, Mungan and Nicholson illustrated that additional oil could be recovered from natural cores after reaching a water-oil ratio of 100 to 1 with the addition of sodium hydroxide. The greatest effect on recovery was noted to occur when the caustic solution was used from the beginning of the flood.
Capillary Trapping in Three-Phase Flow
Authors: Virnovsky G. A. , Skjaeveland S. M. , Helset H. M. 
Published: December 2007

Abstract
The paper presents the results of analytical and numerical studies of the capillary trapping phenomena occurring in 3-phase flow. Based on theoretical results, a numerical procedure and a software package has been developed providing an easy way to compute distribution of residual oil in a heterogeneous 1D reservoir.
For a given set of relative permeabilities and capillary pressure, the saturation profiles are generated for different types of wettability of the rock and different types of boundary conditions which are relevant for reservoir and laboratory. The main characteristics influencing the process of capillary trapping are wettability type, and the 2 capillary numbers showing the relative strength of capillary forces for oil-water and oil-gas as compared to the viscous forces. It is shown that the type of boundary conditions as well as wettability will strongly influence the amount of the capillary trapped oil and gas.
The Effect of Viscosity on Drag Reducer Performance in Oil Pipelines
Authors: Lescarboura Jaime A. , Wahl Harry H. 
Published: December 2007

Abstract
The polymeric drag reducer CDR has been tested in the laboratory in oils with viscosities ranging from 3 to 48 cp and in product and crude oil pipelines at 3, 5, and product and crude oil pipelines at 3, 5, and 9 cp. Three regions have been identified in the drag reduction spectrum—(1) an extension of laminar flow where drag reduction increases with increasing flow velocity, (2) a transition region where drag reduction first decreases and then increases again with increasing flow velocity, and (3) a region of maximum constant drag reduction. Above a certain critical concentration of polymer, the transition from the laminar flow extension to the maximum constant drag reduction occurs without any inflection points. Below the critical concentration the extension of laminar flow increases with increasing oil viscosity. In the region of extension of laminar flow, significant drag reductions (up to 50 percent) were obtained.
The laboratory data show that CDR is an effective drag reducer in all the oils tested regardless of their viscosity. The results of pipeline field tests in products and oils from 3 to 9 cp viscosity show that in the full turbulence region the performance of CDR is independent of viscosity.

Introduction
Drag reduction is the increase in pumpability of a fluid caused by the pumpability of a fluid caused by the addition of small amounts of additive to the fluid. It occurs only in turbulent flow. At a given flow rate, the percent drag reduction is given by
(1)
where delta P is the pressure drop in the pipe without drag reducer, the base pressure drop, and
delta Pp is the pressure drop in the line when drag reducer is added to the fluid.
Because large pressure drop reductions can be obtained with small amounts of drag reducer, drag reduction has a wide potential application within the oil industry. potential application within the oil industry. We have reported recently on a drag reducing polymer, CDR, that gave substantial drag reduction in crude oil pipelines. However, these tests were limited to relatively low viscosity fluids.
California Oil Industry's Solution for Oil Spill Control in the Santa Barbara Channel
Authors: Norton R.W. 
Published: December 2007

Abstract
Since the well-known Santa Barbara oil spill in January, 1969, the oil industry in California has devoted considerable manpower and money toward prevention of oil spills and effective control and cleanup of any accidental spill on the water or the land. Major oil companies have developed detailed oil spill contingency plans to improve their capabilities to control and cleanup oil spills, and both the Oil Operators and the Contractors have increased their inventory of cleanup equipment and their knowledge of control and cleanup operations. The most significant step toward controlling pollution from spills has been the formation of pollution from spills has been the formation of Clean Seas Incorporated, a non-profit corporation, headquartered in Santa Barbara, which will supply the equipment, materials, trained manpower, and operational know-how necessary to handle oil spills in the ocean from Pt. Dume to Estero Bay. The formation and funding of Clean Seas Incorporated by 14 major oil operators in the Santa Barbara area represents a commendable effort on their part to protect the environment of the area. The successful formation of Clean Seas Incorporated will pave the way for setting up similar cooperative oil spill control organizations in other major commercial areas on the West Coast and in Alaska.

Introduction
The oil spill that began on January 28, 1969, in the Santa Barbara Channel was undoubtedly the most publicized incident of its kind. It stirred up an emotional storm that is still raging. More information and even more misinformation has been put in public print about this event than, perhaps, public print about this event than, perhaps, any other single incident in recent oil history. There is great public confusion and understandable public concern. Political reverberations still echo in Sacramento and in the Halls of Congress.
But amid the confusion of having to defend itself from both founded and wildly unfounded criticism, the oil industry saw one point to be perfectly clear. There was honest need to improve existing capability to deal with massive offshore oil spills. It was in response to this recognition that Clean Seas Incorporated came into being as the cooperative effort of the 14 major oil companies operating in the Santa Barbara Channel. It appears that Clean Seas Incorporated may also be the prototype of similar efforts needed elsewhere.