bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of ADCO's Environmental Management System (EMS)
Authors: Pratt Mark. D.
Published: December 2007

The purpose of this paper is to relate the experiences and lessons learned by the Abu Dhabi Company for Onshore Oil Operations (ADCO) as we have been developing our Environmental Management System (EMS) over the last two years. The opinions expressed in this paper are mine as Environmental Protection Advisor for ADCO. I have made several suggestions that I hope can help EMS implementation in similar companies just beginning the process.

ADCO is the largest of the Abu Dhabi National Oil Company (ADNOC) Group companies and is responsible for exploring and producing the onshore crude reserves in Abu Dhabi Emirate. ADCO consists of five major producing fields (Bab, Asab, Sahil, Shah and Bu Hasa) located in desert environments and the Jebcl Dhanna tank farm and shipping terminal located adjacent to a natural port on the north-western coast of Abu Dhabi. We are also beginning to develop and appraise some of our coastal-lying concession areas. ADCO's operations and therefore responsibilities begin at the seismic phase and extend to drilling, completion, production, gas/oil/water separation and pipelining of the crude to our storage and shipping terminal. Most associated gas produced in our fields is processed by our sister company, GASCO.

In 1994, ADCO senior management made a strong and visible commitment to improve the Company's environmental performance by expanding its Environmental Protection Group (EPG), retaining an experienced environmental consultant to perform an environmental baseline survey of the entire ADCO operation and authorising early development of an EMS to manage the ADCO environmental programme.
Prediction of Two-Phase Flow Through Chokes for Middle-East Oil Wells
Authors: Elgibaly A. A. M. , Nashawi I. S.
Published: December 2007

Accurate prediction of multi-phase flow through chokes is required for modem production design and optimization of oil well performance. Most of the Middle-East oil wells are uniquely characterized with high production rates. Several correlations that relate the choke size with other variables involved in the multi-phase flow phenomena have been proposed in the literature. The validity of these correlations for Middle-East oil wells has been assessed in this study.

A new correlation has been developed to describe the choke performance of the Middle-East oil wells. The proposed correlation is similar to the Omana-type correlations based on dimensional analysis. This correlation was examined against a wide range of well test data collected from various oil fields in Egypt, Kuwait, Libya, and other Middle-East countries. Statistical analysis was used to compare the accuracy of the results obtained from the new correlation with those from other correlations. The effect of different PVT correlations on the predictive accuracy of the fluid flow equations has been also investigated. These properties included the surface tension of the gas/oil system, gas compressibility factor, solution GOR, and oil volume factor.

The developed correlation provided highly accurate results compared to the other existing correlations. This correlation is applicable for critical flow conditions and requires knowledge of the PVT data. This study showed that the use of different PVT correlations resulted in slight variation in the accuracy of the developed correlation.

Further analysis has been conducted in the present study on the Gilbert-type empirical correlations. Results emphasized the linear relationship between flow rate and upstream pressure for critical flow.
Delineation of Organic Richness and Thermal History of the Lower Cretaceous Thamama Group, East Abu Dhabi: A Modeling Approach for Oil Exploration
Authors: Taher Ahmed A.
Published: December 2007

The source rocks of the Lower Cretaceous Thamama Group in east Abu Dhabi were identified by using wireline logs. This technique was applied to 33 wells which provided a well-sampled new regional pattern of source rock distribution and thickness. The Tharmama Group includes rich source rocks in the Aptian Shu'aiba intra-shelf basin facies and a moderate source rock potential in the dense layers, especially those in the basal part of the Nasr Formation. The reconstruction of the burial and thermal histories indicates that the mature Thamama kitchens are mainly located in the eastern part of Abu Dhabi, adjacent to the foredeep basin and reached optimum maturity levels starting in the Eocene. Westward migration from these kitchens is mainly lateral and updip toward the main Thamama producing fields in central Abu Dhabi. The conclusion that the hydrocarbons migrated laterally is supported by oil to source rock correlation and the vertical distribution of hydrocarbons in the reservoirs.

INTRODUCTION

The Lower Cretaceous Thamama Group of eastern Abu Dhabi (Figure 1) includes several important hydrocarbon reservoirs. This sequence was deposited on a carbonate platform and varies in thickness from 2,500 to 3,000 feet (ft). The overlying Middle Cretaceous Nahr Umr shale and the basal part of the Nasr Formation are regional seals (Figure 2). Local seals also occur as intercalated dense carbonate layers.
Variable Rate Pressure Drawdown Analysis for Gas Wells
Authors: Nashawi I S. , Elgibaly A. A. M.
Published: December 2007

Pressure transient tests of gas wells, in general, are peculiar in their nature. They possess additional degree of difficulty when compared with the oil well tests. The peculiarity of gas well tests over oil well tests is due to the non-linearity of the diffusivity equation and to the presence of non-Darcy flow or rate-dependent skin effect around the wellbore. Moreover, the constant flow rate requirement in conventional pressure drawdown tests adds another dimension of difficulty to the tests, because this condition is hard to fulfill in field applications.

In recent years, several approaches have been proposed to solve these problems. For instance, normalized pseudopressure and pseudo-time have been used to linearize the diffusivity equation. Variable rate tests were proposed as an effective substitute for single point test. Trial-and-error procedure or at least two constant rate tests were used to determine the rate-dependent skin. Even though the trial and error procedure and the two rate tests provide good estimates of the non-Darcy skin, they are time consuming and hard to apply in practice.

This paper presents a simple technique to analyze variable flow rate data of gas wells with turbulence and damage. The proposed method uses normalized pseudo-variables to avoid the non-linearity in the diffusivity equation and it is straight-forward in the sense that it does not require a trial-and-error procedure or two rate tests. The method involves the construction of two different plots. The formation permeability is obtained from the slope of the first plot, whereas the inertial turbulent flow coefficient and the mechanical skin factor are obtained from the slope and intercept of the second plot.

The proposed method is simple and provides accurate and reliable results in a short testing period when compared with other methods. A field case and a simulated example are used to illustrate the applicability of the proposed method.
A Fully Implicit, Three-Dimensional, Two-Phase, Control-Volume Finite Element Model for the Simulation of Naturally Fractured Reservoirs
Authors: Naji Hassan S. , Kazemi Hossein
Published: December 2007

This paper describes the formulation and application of a fully implicit, three-dimensional, two-phase (water and oil) mathematical model for the simulation of naturally fractured reservoirs. The model equations are discretized using the control-volume finite element (CVFE) scheme where pressure terms are treated in a finite element manner while mobility terms are upstream-weighted as in the usual finite difference (FD) method. The form of the discretized equations is similar to the usual FD method, thus standard techniques are used to solve the Jacobian. The equations are solved fully implicit for pressure, saturation, and wellbore variables using the iterative Newton-Raphson method of solution.

Two field scale examples, that were first presented by Kazemi et al., were used to test the model. These include a quadrant of a five-spot pattern, and a five-well fractured reservoir having dip and natural water influx.
Physical and Chemical Performances of Fiberglass Tubulars in Super Critical Application of CO2
Authors: Arian G. Hossein
Published: December 2007

Long term chemical and physical performance of aliphatic amine cured fiberglass Tubulars in high pressure super critical application of CO2 in both cyclic and static conditions have been investigated. No physical or chemical degradation was detected at the selected test condition of 2300 PSI and 120 F of carbon dioxide in cyclic or static conditions. Further analysis suggests a slow rate of CO2 penetration into the amine cured epoxy laminate. The failure mechanism model developed and presented here suggest a predictable failure based on stress due to pressure and temperature. The verification of the model presented paves the way for major simplification and cost reduction potentials in future construction and extension of a CO2 WAG Piping Systems, by combining CO2 and water injection lines into one.

Introduction

Carbon Dioxide (CO2) injection is being used commercially to produce oil that normally would be unrecoverable. CO2 is injected in the super critical state at a surface pressure of about 1500 to 2500 PSI. "CO2 is an efficient injectant because it dissolves readily in both oil and water, with CO2 solubility increasing with increasing pressure. The dissolution of CO2 in oil increases or swells the crude volume and decreases the crude viscosity, which results in a more mobile oil bank and improved sweep efficiency." (Reference 1).

Generally, in order to prevent channeling and maximize flood profitability, implementation of water alternating gas (WAG) injection becomes necessary. The CO2 WAG systems increases corrosion concerns drastically due to formation of carbonic acid and the contamination of produced water used for re-injection for metallic tubulars.

With a proper selection of raw materials, outstanding results have been achieved in the past 25 years using fiberglass tubulars in low pressure or low concentration applications of CO2 to combat corrosion problems. However, a few initial set backs in the early 80's, due to improper raw material selections, connection integrity, misapplication, or pure mishandling of the product, kept the usage of FRP Tubulars to a few selected projects for high pressure CO2 WAG Systems. The information presented here is intended to provide a reliable and predictable failure mechanism to facilitate selection and operation limitation of FRP Tubulars for a trouble free corrosion controlled high pressure CO2 WAG Piping System.
Permeability Scaling in a Numerical Coning Model
Authors: Dutta V.K. , Arnold M.D.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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.
Coiled Pipeline Technology: A Gulf of Suez Case History
Authors: Hoffman John G. , Little Chester T. , El Lathy W.F. , Glanville Shawn M.
Published: December 2007

Coiled "tubing" is a rapidly growing pipeline technology. Until recently coiled tubing was used primarily by service companies for coiled tubing workovers. As the technology expanded the industry began using coiled tubing for other applications such as drilling, coring, logging, well clean out operations and artificial lift. As the tubing mills began producing larger sizes, it became possible to consider using coiled tubing as pipelines. The application of coiled tubing as a pipeline began in the Gulf of Mexico. The early results supported the application as being a low cost, time saving, economic alternative to conventional welded pipe for flowlines. Coiled pipe applications have been used in 4 to 100 feet of water in the Gulf of Mexico area and the installation techniques have varied significantly.

In 1994, the Gulf of Suez Petroleum Company (GUPCO), a joint venture company between Amoco Production Co. and the Egyptian General Petroleum Co., embarked on the first international application of the 3.5 inch coiled pipe using a dynamic lay procedure. The cost savings from the first two jobs were estimated to be in excess of 70% when compared to the traditional lay vessel charges. Engineering design and field experience was shared at the Middle East Oil Show in Bahrain during 1995 (SPE 29786). Subsequently GUPCO has taken a leading role in the application of coiled pipe technology with the 1996 installations using the first production of 4.5 inch coiled pipe, one of which is a record setting 65,000 ft. high pressure water supply line. Cost savings of this larger diameter coiled pipe are still yielding 55% cost savings over the conventional barge lay techniques.

Introduction

The Gulf of Suez Petroleum Company has been using coiled pipe technology since 1994. Since that time the technology has grown with larger diameters being offered. These larger pipes have enabled the company to examine additional opportunities in the Gulf.

To date the company has installed 45,000 feet of 3.5 inch and 72.000 feet of 4.5 inch coiled pipe. In 1994 GUPCO embarked on its first two coiled pipeline projects using the 3.5 inch material. By 1995 a new larger diameter coiled pipe was being offered. The 4.5 inch material offered additional application in the Gulf and GUPCO pursued three additional projects. In January of 19% the company installed the world's first and longest 4.5 inch coiled pipeline.

P. 605
Multi-Zone Gravel Pack Techniques: Case Studies From the South China Sea Xijiang Development
Authors: Bennett John Scott , Sanders T. K. , Grigsby Tommy , Fucun Yuan , Liang Zhou , Yaxin Bai
Published: December 2007

Xijiang is the first Pearl River Mouth Basin Development in the South China Sea employing gravel packs. These fields, comprised of multiple-layered reservoirs, are characterized by unconsolidated, friable, and high-permeability sandstones that must be commingled for economical production. This paper will discuss the specific reservoir characteristics and parameters that affected completion scenarios in the development of these fields and how the needs for sand control, zonal isolation, high-rate production, and reduced completion duration have been addressed.

Particularly significant in development of the projects has been the design of two completions systems specific to the Xijiang reservoir conditions that accomplish gravel packing and mechanical isolation of individual sands while minimizing the number of trips made into the wellbore. The single-trip dual-zone (STDZ) system is used when two zones must be gravel packed, and the multi-zone system has been employed when there are as many as 8 zones in one wellbore that must be gravel packed.
Handling Fluid Properties in Reservoir Simulation Studies
Authors: Ridings Robert Lewis
Published: December 2007

The reservoir engineer today is able to evaluate and predict reservoir performance much more precisely through the application of multi-dimensional models to mathematically simulate reservoir behavior. The additional precision requires more attention to the handling of reservoir fluid properties than the traditional material balance studies.

This paper discusses the problems involved and reviews several techniques which have been employed to achieve improved accuracy in the application of fluid properties in reservoir studies. The techniques presented attempt to consider variations in properties presented attempt to consider variations in properties spatially within the reservoir as well as variations with pressure and composition.

Reservoir Bubble Point

Rather than computing one point in time at which the overage reservoir pressure declines to an average reservoir bubble point pressure, model studies reflect the more realistic situation in which local areas become saturated while other areas may remain undersaturated — at least for a time. By their nature, model studies reflect this type of situation and the handling of fluid properties in the model must be appropriate to the situation.

The normal concept of average reservoir saturation pressure disappears in model studies. Figure 1 shows pressure disappears in model studies. Figure 1 shows how a reservoir may be sub-divided into blocks for a two-dimensional study. The pressure and saturation and the resulting fluid flow are calculated at each block over short time steps. As an area of the reservoir becomes saturated and solution gas is released from the oil, that evolved gas may migrate away from the area where it is released. If the pressure in that area increases, even temporarily, the oil must then be treated as undersaturated. Also, the evolved gas may tend to re-saturate the oil in another area of the reservoir.

The type of problem encountered in this type of situation may be illustrated by referring to Figure 2 which shows a typical formation volume factor curve. If the pressure declines in one part of the reservoir to a point well below the original bubble point, the correct formation volume factor would be determined on the "saturated oil" portion of the curve.
A Simplified Well Control Model for Horizontal Slimholes and Coiled Tubing Drilling
Authors: Choe Jonggeun , Juvkam-Wold Hans C.
Published: December 2007

This paper presents the development of a simplified two-phase well control computer model to simulate gas kicks. The paper identifies key factors in the prediction of kick behavior based on a comparison between a fully implicit dynamic two-phase model and a single-phase model. The model also analyzes kick responses for directional and horizontal slimholes and wells drilled with coiled tubing. Directional and horizontal wells consider multiple build-up rates. This paper highlights the effect of homogeneous or locally high pressured horizontal wells and the effect of reeled coiled tubing. This paper also examines theoretical kill sheets for several well trajectories from vertical to horizontal and for coiled tubing drilling. Theoretical kill sheets are compared with conventional kill sheets.

The simplified two-phase well control model developed in this study is reliable and stable. It can handle vertical, directional, and horizontal wells with multiple build-up rates and hold sections and does not have any numerical problems such as may occur with a dynamic two-phase well control model. For directional and horizontal wells with high build-up rates, choke pressure changes rapidly without much kick expansion because of vertical height change of the kick mixture as the kick moves through the curve.

A conventional kill sheet is good enough for a conventional large diameter vertical well with uniform well geometry. However, a theoretical kill sheet should be used with some amount of over-pressure for directional, and horizontal wells, especially when those are slimhole wells or are drilled with coiled tubing.
Selection and Qualification of Drill-ln Fluids for Horizontal Wells in Unconsolidated Sands
Authors: Hale Arthur H. , Lau Hon Chung , Bernardi Louis A. , Albrecht Michele S. , Faircloth Robert J. , Morgenthaler Lee N. , Kielty Jim M.
Published: December 2007

Much of the development using horizontal well technology had been centered around drill-in fluids. These fluids tended to be excellent for completion purposes but poor drilling fluids, and although success was recorded throughout the world, many areas that required more robust fluids were not being drilled. Well conditions such as higher temperature (>175°F), depleted sands, intermittent sand shale layers, low fracture gradient pore pressure spread, and high weights for wellbore stability were limiting the application of horizontal well technology. Not only were fluids not available to drill with, but also it was unclear what methods or techniques were needed for wellbore clean-up.

Because of need for drìll-in fluids, an effort was undertaken in concert with the service companies to develop fluids that met both drilling and completion requirements. The effort was systematic in that established criteria had to be met for both drilling and completion. These criteria included requirements on fluid rheology, thermal stability, lubricity, fluid-loss control, filtercake properties, and removal of filtercakes after drilling leading to low/no formation and screen damage. Laboratory tests to measure candidate drill-in fluids against these criteria were established. Both water and oil or synthetic invert fluids were developed.

In this paper a quality procedure is shown for validating fluids on a screening basis followed by specific evaluation of methods to mix, maintain on the rig, and ultimately to complete. Our field experience has shown that this quality control procedure is crucial to the high success rate of Shell's horizontal wells in the Gulf of Mexico. Data are shown which lead to guidelines for drilling and completing wells with varying conditions.
Analysis of the Steam Assisted Gravity Drainage SAGD Process Using Experimental/Numerical Tools
Authors: Nasr T. N. , Golbeck H. , Lorimer S.
Published: December 2007

There has been a keen interest during the last decade in the application of the steam assisted gravity drainage (SAGD) process as a recovery strategy for oil sands and heavy oil reservoirs. The recent success of field pilot demonstrations in Alberta and Saskatchewan has further accentuated the need to understand process mechanisms and determine techniques to accelerate recovery rates for improving economics. This paper provides an in depth analysis of the SAGD process using numerical and experimental tools. Two-dimensional scaled gravity drainage experiments, designed to represent heavy/extra heavy oil reservoirs, were used to calibrate the thermal reservoir simulator STARS. Visual observations of the development of the steam chamber (gravity cell) were made during the experiments and compared to numerical model predictions. The results obtained provided insight into the effect of key parameters such as permeability, pressure difference between the wells, capillary pressures and heat losses on process performance. A detailed study on the effect of permeability on source/sink simulation of the SAGD process demonstrated the importance of the initialization or transient phase of the process. The duration of the initialization phase increased as the permeability decreased, indicating that this phase occupied an increasingly significant portion of the entire drainage process as permeability decreased. The sensitivity of the validated numerical model to a number of key parameters required for numerical simulation of the process are highlighted in the paper. The effort is intended as a precursor to modeling field scale gravity drainage processes. The ultimate application of the work is in thermal heavy oil recovery operations using steam assisted gravity drainage.
Screening of Reservoirs For Exploitation by Application of Steam Assisted Gravity Drainage/Vapex Processes
Authors: Singhal A. K. , Das S. K. , Leggitt S. M. , Kasraie M. , Ito Y.
Published: December 2007

In an environment of low oil prices and low economic returns for heavy oil operations, SAGD and VAPEX processes appear very promising from a technical point of view. The purpose of this paper is to present guidelines for screening heavy oil reservoirs for exploitation by Steam Assisted Gravity Drainage (SAGD) and VAPEX processes.

Viability in the field would be strongly governed by factors such as net pay thickness, oil viscosity, presence of gas cap or bottom water, barriers to vertical flow, containment of the steam or vapour chamber within the target area, lateral and vertical extent of steam/vapour chambers, number of new horizontal/vertical wells to be drilled, solvent recovery, facilities requirements, etc.

Exploitation viability of heavy oil reservoirs is evaluated under different reservoir settings using a combination of reservoir/geological analyses and numerical simulation. This evaluation helps provide guidelines for screening reservoir prospects for the application of SAGD/VAPEX processes. The viability of these processes is sensitive to the reservoir characteristics of the specific target areas.
Control of Wax Deposition: An Experimental Investigation of Crystal Morphology and an Evaluation of Various Chemical Solvents
Authors: Ferworn Kevin A. , Hammami Ahmed , Ellis Herb
Published: December 2007

Four commercial solvents and o-xylene have been tested for their effectiveness in remediating paraffin (wax) depositions from three different dead oils. The dead oils were sampled from the North Sea, Alberta and Gulf of Mexico, respectively. Representative field solvent/oil concentrations of 2000 and 4000 ppm (vol) were prepared for each oil and solvent considered in this work. Two state-of-the-art techniques, namely a cross polar microscopy (CPM) and a rheometrics mechanical spectrometer (RMS 800), were used to study paraffin crystal habits and/or morphologies at 32°F, wax dissolution temperatures (WDT), and pour point temperatures of the three dead oils with and without solvents. It is found that in almost all cases, the 2000 ppm (vol) solvent concentration yielded similar or better remediation results than mixtures with 4000 ppm (vol) solvents. More importantly, it is shown that the remediation of wax deposition depends not only on the solvent concentration but also the type of oil and, in turn, waxes being treated (i.e., case specific). In some cases, the relatively cheap solvents outperform the more expensive o-xylene in dissolving wax deposits. Finally, a laser based solids detection system (SDS) was used to study the effect of o-xylene on the wax appearance temperature (WAT) of a second live fluid from the Gulf of Mexico.