bluuebunny/crossref_metadata_2025 huggingface dataset:
The Comprehensive Technology of Horizontal Drilling And Development In Shengli Oilfield
Authors: Ye Feiting , Sun Jiancheng , Wang Baoxin , Li Hongwei
Published: December 2007

In the last few years, the horizontal drilling technology in Shengli Oilfield has developed at a rather rapid pace So far, 30 horizontal wells of different types have been completed in various hydrocarbon reservoirs. This paper emphasizes the design and drilling practices in the horizontal exploratory wells and the horizontal development wells of viscous oil gravel reservoirs in Shengli Oilfield. The application and technology of horizontal well to other oil and gas reservoirs are also presented.
Three-Stage Stochastic Modelling Method To Characterize Reservoir With Fluvial Facies
Authors: Wang Jiahua , Zhang Tuanfeng
Published: December 2007

One of purposes of reservoir characterization is to delineate reservoir heterogeneities as truly and effectively as possible. Reservoir heterogeneities are one of main factors to affect recovery ratio. Understanding of reservoir heterogeneities is useful to recognition of effects of barrier layers on fluid flow in reservoir, to clear seeing of spatial distributions of sandbodies and permeability, and to correct evaluation of spatial distribution of residual oil[1].

A number of studies shows that stochastic modelling and stochastic simulation of reservoir with geostastistics is an effective method to evaluate reservoir heterogeneities quantitatively[2][3][4].

Reservoir heterogeneities exist on various observation scales of reservoir, and full into large-scale heterogeneities and micro-scale heterogeneities. Different heterogeneities with different scales restrict and affect each other. More attention has been paid to stochastic modeling of sedimentary facies. The reason is that spatial distribution of sandbodies or geometry of sandbodies is important to control reservoir behaviour, to make development plan, and to estimate reliable recovery ratio of oil and gas [5] [6] [7].

Multi-stage stochastic modelling of reservoir, as an advanced method for reservoir characterization, can show various heterogeneities with different scales, and embody constraint relationships among these heterogeneities. It can make simulation of spatial distribution of sedimentary facies match with simulation of spatial distribution of petrophysical parameters. The process and results with multi-stage stochastic modeling will have more reasonable geological meaning than other stochastic modeling

The systems for reservoir characterization, HERESIM developed by IFP and Geostatistical Center of Paris Mining Institute, and MOHERES developed by Normay State Oil and Norway Computing Center, both have used two-stage stochastic modeling.

This paper proposes a methed for three-stage stochastic modeling of reservoir with fluvial facies. This method consists of three models: stratification plane configuration model, sandbody framework model, and petrophysical parameter distribution modeL A case study, presented in this paper, indicates that this method is especially suitable for fine quantitative description of complex fault block reservoir with fluvial facies.
Predicting and Scanning of Wellbore Trajectory in Horizontal Well Using Advanced Models
Authors: Deli Gao
Published: December 2007

This paper discussed the methods to analyse the bottom hole assembly in horizontal well and gave the non-linear dynamic governing equation of BHA as well as its initial and boundary conditions. A vector model of rock-bit interaction was established. A new concept of the effective drilling force was proposed. Based on the model and concept, some typical anisotropic formations were classified into 12 categories. Their anisotropic drilling characteristics could be presented in the equations and graphs. In a field example, the deflecting performance of a typical downhole motor assembly with the bent housing and two stabilizers in horizontal well was discussed in detail. The adjacent well distance scanning and plotting method and its engineering application were introduced in the last part.
A Brief Description of Extended Well Testing (EWT) System
Authors: Wu Si
Published: December 2007

This paper discusses mainly the component, characteristics and main uses of extended well testing system, main factors considered in design, and the system application. Component of the system: the system is mainly composed of jack—up platform, floating hose, 2 — point submarine buoy mooring system, and storage tanker.Characteristics of the system: the system can use fully the existing equipment with less investment, gaining benefit early, flexible operation, safety and reliableness, repeated utilization, easy to relocate and low cost.Usage of the system: the system is used in reservoir testing before development reservoir data can be got, reliable asis can be provided for the policy making of oil field development, and the developing risk of oil field can be reduced through the testing. Furthermore, the system can be also used in the development of marginal fields.Main factors considered in the designs the system adopts firstly the new technology of 2—point submarine buoy mooring system and simple process flow sheet with only degassing and no dehydration. Reliable measures are taken to ensure safety production from the angle of design and usage.Usage condition: it is proven by practice that connection and disconnection of the system are very convenient with flexible operation and reliableness. The shuttle tanker can be moored side by side conveniently using 2 — poit submarine buoy mooring system.
The Oil-Water Relative Permeability Behaviour of A Low Permeable Reservoir
Authors: Kevin Li , Yirong Jiang , Zhijian Dai , Ying Hong
Published: December 2007

Much attention is now paid to the development of low permeable reservoirs. However, there is almost a dearth of literature on the study of relative permeabilities in rock samples with low permeability. Group J2S of QL Reservoir is characteristics of low porosity, low permeability and low crude oil viscosity.

Oil-water relative permeabilities of QL Reservoir have been measured at two different oil/water viscosity ratios by using unsteady-state method. The experimental results showed that the oil-water relative permeabilities change with the changing of oil/water viscosity ratio. It is explained that the oil-water relative permeabilities measured at oil/water viscosity ratio close to the oil/water viscosity ratio under reservoir condition coincide with the practical situation of QL Reservoir by comparing the injection-production ratio calculated from laboratory water flooding data with the practical one.

The irreducible water saturations in QL Reservoir rocks range from 27.7% to 35.8% and its average value is 31.5%. The water flooding residual oil saturations range from 11.6% to 21.7% and its average value is 14.8%. Most of the water relative permeabilities at residual oil saturations range from 0.23 to 0.50 and its average value is about 0.388. Oil-Reference and illustration at end of paper water 2-phase flowing limit ranges from 47.8% to 59.0% and its average value is about 53.7%. Moreover, the end water relative permeabilities are correlated with the air permeabilities of rock samples. That is, the bigger the air permeabilities of the rock samples, the higher the end water relative permeabilities.
A Field Study of Horizontal Well Design in Reducing Water Coning
Authors: Wu G. , Reynolds K. , Markitell B.
Published: December 2007

Water and gas coning is a serious problem in many oil field applications. In reservoirs with bottom water, vertical wells are normally completed in the top section of the pay zone to minimize water coning. Similarly, in a reservoir with a gas cap, a vertical well is perforated as low as possible to delay gas coning. Oil production from thin oil layers sandwiched between a gas cap and bottom water, such as one finds in the Amber Field in the Gulf of Mexico presents difficult coning problems in vertical wells.

This paper describes Texaco's efforts to evaluate, justify and drill a horizontal well in Amber Field. The target reservoir contains a very thin pancake oil zone sandwiched between a large gas cap and a strong bottom water aquifer. The production wells were expected to exhibit critical oil rates of approximately 10 STB/day (calculated). Due to the gas and water coning, the vertical wells in the field produce at low oil rates and recovery was in the range of 3% to 4%. This paper details efforts to numerically model the optimum case for vertical and horizontal wells to allow for economic comparisons. The effect of the length of the horizontal wells, their location relative to the current fluid contacts, and the change in performance with production rate are all investigated.

The simulation process involves four individual steps: (1) history matching the adjacent well with coning problems, (2) assessing the current fluid distribution by a coarse-grid model with single-phase producers, (3) calculating the initial rate of a horizontal well, and (4) horizontal-well performance prediction. It is demonstrated that the optimal well position depends on the development term. A horizontal well penetrating the oil column produces more oil and water during the early stage of horizontal well production. In the long run, it appears to be beneficial to place the horizontal well in the gas cap, which gives the highest oil recovery and significantly reduces water coning.
Formation Damage due to Losses of Ca-Based Brine and How it was Revealed Through Post Evaluation of Scale Dissolver and Scale Inhibitor Squeeze Treatments
Authors: Lejon K. , Thingvoll J. Tuxen , Vollen E. A. , Hammonds P.
Published: December 2007

Calcium based brine has regularly been used during workover operations on naturally completed wells without any sign of formation damage, in gravel packed wells which have seen severe losses of Ca based brine production decline was observed.

For some of the gravel packed wells the production decline occurred when bringing the well on production after completion, whilst in others, the loss in productivity occurred after sea water breakthrough.'

In order to increase productivity and confirm the relationship between productivity decline and formation of CaSO4 scale due to losses of completion brine, scale dissolver treatments were carried out.

The use of dissolver chemicals resulted in mobilization and removal of several hundred kilograms of solids from the near wellbore area.

A post-evaluation strategy to provide information about the nature, origin and location of scale was successfully implemented. More importantly, the dissolver treatments resulted in increased oil production.

The findings and lessons learned have had several important implications for gravel pack completions and well treatments in Statoil.
Fractional Pore Volume Acidizing Flow Experiments
Authors: Gdanski Rick
Published: December 2007

A large amount of published literature exists detailing the effects of HF on sandstone cores.1 The bulk of this work concerns flowing large numbers of acid pore volumes through relatively small cores having pore volumes of about 5 to 15 mL. Some HF acidizing studies have analyzed the effluent from these tests to determine ionic composition in an effort to study the chemistry of HF acidizing. Chemical and engineering simulators use the results of such work in an attempt to predict the performance of HF in sandstone formations.2-6 Returns analyses7-9 from many wells treated with HF do not support the results of these multiple-pore volume flow tests and associated simulators. Some researchers now use long-core permeameters to improve the prediction of the laboratory tests and to answer key questions concerning well response to HF acidizing treatments.10-13

It has been recognized that inadequate laboratory experimental models have caused the discrepancies between the experiments and the well returns. To solve this problem, a laboratory acidization apparatus has been designed, constructed, and tested. The apparatus has a pore volume of about 300 mL, which allows fractional pore volume tests to be conducted and effluent to be analyzed on the basis of fractional pore volume. For such a test to be analyzed, the effects from mixing and ion exchange must be considered. A computer code written explicitly for the apparatus evaluates the effluent ionic data.

The apparatus is essentially a 3-ft Hassler sleeve with multiple pressure taps. The sleeve can be packed either with a blend of sand and clay or loaded with a solid core. Two computers and two microprocessors networked together control temperature, valve switching, pressure measurements, flow measurement, pump control, and data collection. A typical two-to four-pore volume experiment requires about 4 to 24 hours to complete, depending on pump rate.

The new apparatus successfully has modeled (1) mixing between two separate fluid stages, (2) ion exchange on bentonite with various brines and acids, and (3) leaching of aluminum from clays by HCl. Results indicate that the new apparatus and analysis tools are particularly suited for the study of HF acidizing chemistry.
Evaluating the Performance of Open-Hole, Perforated and Fractured Water Injection Wells
Authors: Pang Shutong , Sharma Mukul M.
Published: December 2007

The performance, i.e. the half-life of water injectors, is very important to the economics of water injection projects. A simulator is presented to predict the decline in injectivity of water injection wells. Equations are presented that allow us to model open-hole and perforated completions as well as fractured wells. The mechanism of injectivity decline can be determined by comparing core flow test data with one of four type curves. The transition time is used to determine when external filtration becomes dominant so that the appropriate models can be used for early and late time.

The simulator can be used whether or not core flow data is available. Empirical equations are provided to estimate the filtration parameters if core flow test data is not available. The simulator is easy to use, has interactive input and output and is available for PCs and Unix workstations. Examples are provided to show how the simulator can be used to predict the performance of injectors in a variety of cases. The simulator predictions are compared with experimental data. The simulation results are then used to suggest the optimum water quality that will minimize the total cost of water treatment and periodic well stimulation.
Alba Field Cased Hole Horizontal Gravel Pack - A Team Approach to Design
Authors: Alexander Karen , Winton Suzanne , Price-Smith Colin
Published: December 2007

A 700’ cased hole horizontal well was gravel packed and completed in the Alba Field, Central North Sea. The completion incorporated a number of new technologies adopted for a horizontal cased hole completion including both equipment and fluids. The zone was completed in 2 stages using a horizontal stack pack approach. Perforation packing was optimized by performing a staged acid prepack with the guns in the hole utilizing a low density synthetic gravel substitute in a shear thinning carrier fluid. This was a world first achievement at a cased hole gravel pack using the stack pack approach in a horizontal well. A solids free fluid loss control material was evaluated and chosen for the high permeability Alba sands (3 Darcy). Extensive lab testing was performed to ensure minimal damage from various fluids. A 30' physical model was used to optimize annular pack efficiency. A gravel placement computer simulation was used to design pump rate, sand concentration and gel loading in order to optimize annular and perforation pack efficiency.
Quantifying Porosity and Estimating Permeability from Well Logs in Fractured Basement Reservoirs
Authors: Sibbit Alan M.
Published: December 2007

Low porosity fractured reservoirs have been successfully described using a combination of high resolution geometrical information from borehole images together with deeper penetrating log evaluation methods.

Borehole images from acoustic or electrical scanning tools provide statistics of fracture distribution, first order estimates of fracture opening and porosity, and a basis for geological inference. Their drawback is that, in this environment, the events on the images bear a strong overprint of the drilling process. Deeper penetrating but lower resolution techniques such as Stoneley wave reflectance and deep resistivity log inversion are used to distinguish the deep and permeable fractures that may contribute to flow.

By making some assumptions about the nature of the porosity in basement reservoirs we develop a new method to estimate the porosity and the fraction of this porosity due to fractures. This method makes use of the Kuster-Toksoz acoustic scattering model and requires low frequency measurements of compressional and shear velocities.
Efficient Development Drilling From a Twelve Well Platform
Authors: Eaton Ben A. , Mosley Mark K. , Beakley Bill
Published: December 2007

This paper presents the results of a case study that was undertaken to determine the reasons for the unusually rapid development of a twelve well platform, the third such platform in the immediate area.

Factors that contributed to the successful drilling and completion of these wells are discussed. The overall contribution of the master plan for development is discussed as well as the role of the individual well plans. Specific drilling practices are covered such as the details practices are covered such as the details of the bottom-hole assemblies used for directional control. Since the subject wells were directional slant type holes with high drift angles, primary cementing was of great concern. Cementing techniques that were used successfully are presented. It is shown that a 25 per cent reduction in drilling and cementing time was achieved in this case compared to past practices.

Some of the completion practices were unique for this area and these practices resulted in a further time savings. The overall completion and sand control procedures are discussed in the paper. procedures are discussed in the paper. It is concluded that proper planning. utilization of proper equipment and materials, and excellent on-site rig supervision were the most effective factors in reducing costs for this operation.

Introduction

This case study was initiated due to the unusually fast development drilling from this particular platform. Especially interesting particular platform. Especially interesting was the fact that this was the third such platform in the immediate area. The previous platform in the immediate area. The previous wells had been drilled and completed with the same rig on the second platform and by a very similar rig on the first platform.

In each case a twelve well platform was installed in approximately 170' of water. The platforms were designed to accommodate a minimum size, self-contained rig. Drive pipe guides were arranged in two parallel pipe guides were arranged in two parallel rows of six wells each. Normally, drive pipe was driven in the center six slots at the time the platform was installed. From that point on the work was done with the small, point on the work was done with the small, self-contained rig.
Real Time Expert System (R.T.E.S.) for Rod Pumping Optimization
Authors: Vázquez O. Manuel
Published: December 2007

Through Real Time Expert Systems (R.T.E.S.) technology, it is possible to remotely monitor and control, IN REAL TIME, Rod Pumping automated fields seeking to guarantee maximum production, minimum operating cost, and extending the useful life of equipment.

In Rod Pumping Systems there are analytical tools which allow diagnosing the behavior of the wells[1],[2], such as Dynagraph Charts, Pressure Loggings and Current Consumption. These Loggings are interpreted (using Design and Completion Information) in order to analyze, diagnose the state of the well and finally issue a recommendation, bringing as a result a field action. Generally, these actions are based on S.P.M control of the wells and this can be done automatically, closing the Control Loop.

The main advantage of R.T.E.S consists in the REAL TIME event detection and the immediate reaction to that event. Moreover, the integration of R.T.E.S with Mathematical Models and Simulation Models allows to predict events before they happen and to take field actions.
"OFFSHORE MERCURY" and Her Maiden Voyage
Authors: Blight Graham J.
Published: December 2007

The OFFSHORE MERCURY is a self-propelled self-elevating drillship which can undertake unaccompanied major ocean voyages and field moves. She can be used for exploratory or development work in the offshore oil and gas industry.

Because of her self-propulsion capability the vessel is classified and registered just like a ship. As a result of this, some technical and legislative problems arose during construction and in respect of her operation. Some of these matters are considered with reference to the corresponding solutions which were adopted so that the appropriate rules of the regulatory bodies were satisfied.

All major construction and necessary outfit work was completed and the vessel sailed from the River Clyde in Scotland on December 16th, 1969. Thus the Mercury commenced her maiden voyage en route to Bahia Blanca in the Argentine. The significance of this voyage as a proving experience for the design and engineering of the concept is described in the narrative.

PRELIMINARY REMARKS PRELIMINARY REMARKS Nearly three years ago it was decided that the drilling capabilities of a successful and proven design of self-elevating platform should be combined with the self-propulsion characteristics of a normal ocean-going ship.

The beauty of this idea lay in the long term economic advantages to be gained, insofar that the burdensome expense of tugs would be eliminated at times of maneuvering on, or of changing location. In addition it was apparent that significant savings on the cost of voyage insurance could be made since the vessel would sail under her own power. This is not so expensive as the greater risk assumed by a towed vessel. Also, with an appropriate speed the vessel would get to location faster than if towed and thus in the long term spend a greater proportion of her time in the drilling proportion of her time in the drilling or earning capacity.

The philosophy of the initial design process and development for this new process and development for this new class of drillrig was presented to the Offshore Technology Conference 1969 (ref. 1).
Predicting Production Using a Neural Network (Artificial Intelligence Beats Human Intelligence)
Authors: Boomer Robert J.
Published: December 2007

Petroleum professionals, that is engineers and geoscientist, routinely make recommendations to drill wells. This process requires the generation of a production profile, oil producing rate versus time, which is a key component in the final economic decision of whether or not to drill the well. The success of the drilling program, and possibly the professional's career, rests, to a high degree, upon the accuracy of this predicted production profile. The more accurate this prediction the more certain the economic value of the recommended drilling location. This paper looks at this predictive process as used in the Vacuum Field of New Mexico. It explores the predictive methods used in the past and reports on their accuracy. A new method, using artificial intelligence, is presented which improves upon the accuracy of this process.
Parallel Processing Applied to Local Grid Refinement
Authors: Bowen Garfield R. , Leiknes Jorgen
Published: December 2007

Hybrid gridding techniques provide simulation engineers with an efficient technique for refining a simulation grid in regions of the reservoir where fine detail is required. Local grids are usually required near wells to resolve coning effects. This paper describes the implementation of a hybrid gridding system where the individual local grids are processed on separate processors.

The implementation is suitable for a range of distributed memory parallel computers including a cluster of workstations linked by an Ethernet type local area network.

The basic algorithm solves the global grid with large time steps. This establishes boundary conditions for the local grids which are solved independently with small time steps. The global grid is computed on a master processor with a number of slave processors for the local grids. The algorithm allows the dynamic load balancing of the parallel work and provides a fault tolerant system for the local grids.

The system is applied to a full field simulation study, employing a network of workstations. The performance is assessed on both a dedicated cluster of machines and in a typical oil company working environment.
An Algorithm for the Visualization of Stochastically Generated Colour Images of Reservoir Attributes, Structural Information and Reservoir Boundaries
Authors: Oscar G. , González H.
Published: December 2007

Visualization of reservoir models, integration of a variety of relevant information and generation of final maps on both computer screen and paper, are important parts of reservoir modelling work. The automation of the map generation process enhances the visualization of models integrating multiple geological features, improves quality and reduces time requirements.

This paper presents an image processing algorithm, developed on workstations, which enhances the integration of information used in visualizing and representing reservoir models and related geological-engineering characteristics. The algorithm can integrate images of: Stochastically generated colour maps of reservoir attributes.Scanned structural reservoir maps including faults as well as borehole locations and names.Scanned maps of reservoir boundaries.

This information is digitally integrated into a single colour map that can be manipulated on the screen or printed on paper. Part of the work is developed to extend the visualization of two dimensional maps such as structural maps into three dimensions without relying on digitizer tables. The practical aspects and visualization capabilities of the algorithm are demonstrated with examples.
An EUB Review of In Situ Oil Sands Bitumen Production
Authors: Sadler K. W.
Published: December 2007

The Energy and Utilities Board (EUB) has, as part of its mandate, responsibility for ensuring the orderly, efficient and economical development, in the public interest, of the oil sands resources of Alberta. With increased focus on oil sands production to replace conventional oil, the EUB sees bitumen production as playing an increasing role as a secure source of energy supply.

The EUB forecast of bitumen production from in situ oil sands projects shows an increase from 21 500 m3/d in 1994 to 33 000 m3/d by the year 2000. This forecast and the historical drilling and production patterns associated with commercial, experimental and primary recovery projects will be reviewed. In addition, comments on horizontal drilling activity and the production attributable to horizontal wells are provided.

Oil sands project development occurs using many different methods and in many different reservoirs. Data on production attributable to the various oil sands formations and the established reserves volumes to year-end 1994 are discussed.

The EUB also maintains a very extensive database on Alberta's oil sands production. A description of the data storage and dissemination capabilities is provided.
Heavy Oil Reservoir Mechanisms, Linbergh and Frog Lake Fields, Alberta Part II: Geomechanical Evaluation
Authors: Solanki S. , Metwally M.
Published: December 2007

Field results from many heavy oil reservoirs in the Lindbergh and Frog Lake fields in northeastern Alberta suggest that primary recovery is mainly governed by the processes of sand production and foamy oil behaviour. Sand production leads to the creation of high porosity zones with increased permeability, while foamy oil generation provides the necessary support mechanism to sustain higher production rates.

PanCanadian Petroleum Limited and Centre for Frontier Engineering Research (C-FER) conducted experimental and numerical studies to understand the various reservoir mechanisms contributing to the high primary production recovery observed in the Lindbergh and Frog Lake fields. Laboratory tests were conducted to study the foamy oil behaviour and evaluate its contribution to the enhanced primary production observed in the field. The numerical modelling included a series of idealized models developed and analyzed to determine the most probable shape of the sand-producing zones. The evaluation focussed on matching not only the observed oil production but also the observed sand volumes removed from the reservoir. The analysis from vertical well simulation was also extended to horizontal wells.

The evaluation of heavy oil reservoir mechanisms for Lindbergh and Frog Lake fields is reported in two parts. Part I includes field testing and preliminary reservoir simulation based on the production data. Part II includes analytical and numerical studies for coupling the effects of sand and oil production, and laboratory testing of unconsolidated sand under foamy oil conditions.
Electrical Resistance Tomography for Monitoring Shallow Enhanced Recovery Processes
Authors: Narayan S. , Dusseault M. B.
Published: December 2007

Currently, Enhanced Oil Recovery (EOR) processes are monitored using gas analysis, geophysical logging, observation wells (P&T), well testing methods, seismic velocity tomography, or inversion of deformation measurements. These methods each have their strengths and weaknesses. Most EOR processes involve massive changes in the formation resistivity because of the introduction of a fluid phase with a different conductivity, or a large change in temperature. Threedimensional electrical resistivity tomography may be a way of tracking propagation of fluid fronts with time. We present general requirements for resistivity tomography in EOR, typical electrode installations to reduce noise and seasonal variations, requirements for a general inversion of a 3-D resistivity problem in EOR, sensitivity analyses for a shallow reservoir case subjected to EOR, and a method of rapid design evaluation of resistivity monitoring. We believe that analysis tools and the technology is now adequate to reevaluate and develop electrical monitoring for EOR applications.
Progressing Cavity Pumping System Applications in Heavy Oil Production
Authors: Dunn L. J. , Matthews C. M. , Zahacy T. A.
Published: December 2007

Heavy oil and bitumen wells were traditionally produced with beam pumping systems. However, in the early 1980's, the introduction of progressing cavity (PC) pumping systems presented an alternative to beam pumps that possessed attributes which were ideally suited for heavy oil applications, The functional design of PC pumps facilitates the handling of viscous and abrasive multiphase fluids, and the lower capital and operating costs of these pumping systems makes them attractive for marginally economic operations. Today, primary heavy oil and bitumen applications are almost exclusively produced with PC pumping systems.

To realize the benefits of PC pumping systems for heavy oil production, several issues must be considered. These include flow losses, sand production, rod string and tubing wear, low bottomhole pressures, power transmission/control and pump selection, sizing and reuse. Based on the results from numerical assessments, laboratory testing and field case histories, this paper presents system design, installation and operation guidelines which address these issues.
Numerical Simulation of Horizontal Wells in a Heavy Crude Reservoir in Venezuela
Authors: Zerpa L. B.
Published: December 2007

In 1993, an aggressive horizontal well drilling program started in a Heavy Oil Field, located in the eastern part of Venezuela. The crude oil is characterized by low gravity (8° API). The main objective of this program is to improve oil recovery and control water invasion.

This paper presents the numerical simulation of the first three horizontal wells in the reentry program and sensitivity analysis considering some parameters, such as vertical/horizontal permeability anisotropy, sand thickness, horizontal length, well-bore diameter, number of branches, angles between branches, and friction effects for cold and hot production.

A pseudo-compositional and fully implicit 3-D thermal simulator was used to obtain all the results presented in this study.

The numerical simulation includes the vertical and horizontal history match and the forecast of oil well production performance. Sink-source and well-bore discretization were used as methods for the horizontal well representation.

Simulation results show that a horizontal well reduces water invasion. It also indicates that the optimum horizontal well length for the Jobo area is 800 to 1200 feet. The vertical/horizontal permeability effect is important only for some specific values of the sand thickness and the horizontal length of the well. The well-bore diameter recommended to drill the horizontal wells is seven inches. In addition, drilling of branches at some angles is an option for improving horizontal well production.

The sensitivity analysis, using the well-bore discretization option, reveals that friction has an important effect on the well oil production. The friction effect is more important when the horizontal well length is increased and in some cases it can reduce the cold oil production around 50%.

Cyclic steam injection simulation using horizontal wells shows an oil production improvement of aproximatly 3% for cicle. When this process is applied, the optimum horizontal length is 800 feet.
Cold Lake Project Recovery and the Role of Foamy Emulsion
Authors: Reilly Bernard T. , Scott George R.
Published: December 2007

Cyclic steam injection stimulates an effective foamy emulsion expansion drive at Imperial's Cold Lake Project. Projected bitumen recovery is 25% of the Clearwater bitumen-in-place on developed pads. Ultimate recovery is estimated to be 232 million cubic metres of bitumen from the development area accessible from the current plants.
Milne Point Schrader Bluff: Finding the Keys to Two Billion Barrels
Authors: Bidinger C. R. , Dillon J. F.
Published: December 2007

Milne Point, North Slope Alaska, contains in excess of 2 billion barrels original oil in place (OOIP) in the shallow, Late Cretaceous, Schrader Bluff Formation. This resource is part of a larger accumulation in excess of 26 billion barrels OOIP overlying many of the deeper producing fields. A small waterflood pilot presently produces 3300 barrels of oil per day (BOPD) of 19 API oil from 2650 acres in Milne Point. Initial average well productivity's of 350 BOPD, low by North Slope standards, coupled with current cost, performance, and fiscal conditions, render the resource uneconomic. A multi-pronged approach dealing with well productivity, drilling and facility costs, and development incentives is underway to save this resource from abandonment. Technological and contractual innovations are considered keys to success. Which keys fit the lock will determine the development of billions of barrels of recoverable oil.
High Temperature Naptha to Replace Steam in the SAGD Process
Authors: Palmgren Claes , Edmunds Neil
Published: December 2007

World-wide experience indicates that thermal methods are the only effective methods for the in-situ recovery of heavy oils. Furthermore, the steady progress within horizontal well technology increases the applicability of thermal methods in conjunction with horizontal wells. The steam-assisted gravity drainage (SAGD) process is the prominent example of the synergism of horizontal wells with steam injection.

The major portion of the dollar per barrel operational cost for steam injection is currently attributed to the generation of steam and water handling requirements. In the future, more stringent environmental regulation might further prohibit the use of water for the recovery of heavy oils.

Naptha is present at the site as a diluent for pumping and pipe line transport of the produced heavy oil. The injection of naptha vapour instead of water vapour combines an effective thermal process with the diluent mechanism of the naptha. We present the results of simple analytical calculations, demonstrating the applicability of naptha-assisted gravity drainage (NAGD) compared to the SAGD process.

Numerical simulations have been performed on a two-dimensional cross section perpendicular to the horizontal well pair. We discuss in detail the reservoir mechanisms present during NAGD. For the conditions studied naptha circulation rates are some 14 times the bitumen production rate. Evaluation of the process shows that it will be economic with naptha recycling and by minimising the naptha remaining in the reservoir.
A Practical Thermal Well Testing Method Including Heat Loss Effects
Authors: Sheng James J. , Ambastha Anil K.
Published: December 2007

Monitoring of swept volume over time is important for assessing the success of a thermal project. Falloff tests are commonly used to estimate swept volume for steam injection projects. Steam-injection falloff test data can be significantly affected by heat losses. A well test analysis method to include the effects of heat losses was published in Reference 1. However, one of its shortcomings is that the method requires a knowledge of the rock permeability to analyze test data.

This paper presents a practical method to overcome the proceeding and other shortcomings of the method presented in Reference 1. In our proposed modified method, we rely on pressure derivative graphs to identify the flow regimes, and to improve the analysis accuracy significantly. Numerically-simulated steam-injection falloff test data are analyzed using the previous methods and the modified method of this paper, showing the practicability and improvements resulting from the modified method of this paper.

The modified method presented in this paper should be of considerable help in analyzing falloff test data affected by significant heat losses. The modified method of this paper is also capable of demonstrating whether the effects of heat losses are significant for a given test data set.
Influence of Inelastic Rock Properties on The Stability of a Well-Bore
Authors: Daemen J.J.K. , Fairhurst C.
Published: December 2007

The rock around a well-bore is subjected to a stress field which can-be considered to be composed of four parts:

the virgin stress in the rock the change in this stress field caused by creating the opening the fluid pressure inside the well the pressure caused by the flow of the fluid towards the hole.

An additional component can also be developed if oil withdrawal causes compaction of the oil bearing formations, leading to subsidence of the overlying rock mass. Whether the well will be stable or not depends upon the behaviour of the rock in this stress field.

The stress distribution around a circular well-bore has been calculated by Paslay and Cheatham for an elastic system with radial symmetry and steady state fluid flow into the well-bore. They showed in particular that the rock strength required around the hole can be influenced very significantly by a change in permeability of the rock in the immediate surroundings of the hole. permeability of the rock in the immediate surroundings of the hole. Rock failure is most likely to occur in this zone. Once the rock strength is exceeded it is necessary to include the behaviour of the broken zone in the analysis.

As an initial step we can consider the situation of a vertical cylindrical hole with internal fluid pressure Pi in a rock mass where the virgin stress in the horizontal plane is P in all directions. The radius to which the rock will break* can be calculated from the equilibrium equation:

(Equation 1)

and the expression for the behaviour of the broken rock :

(Equation 2)
Mechanisms of Formation Damage and Permeability Impairment Associated With the Drilling, Completion and Production of Low API Gravity Oil Reservoirs
Authors: Bennion D. B. , Thomas F. B. , Bennion D. W. , Bietz R. F.
Published: December 2007

The economic production of heavy oil reservoirs requires an indepth understanding of the specific mechanisms of formation damage which are unique to these types of formations. This paper will provide a brief description of some of the dominant mechanisms of permeability impairment which can occur in low API gravity oil-producing zones. These include:

Drilling induced damage solids entrainmentfines migrationrock/fluid incompatibilitiesfluid/fluid incompatibilities Reactive clay induced damage Formation of emulsions (water-oil, oil-water) Foamy oil phenomena Sand control and consolidation issues Completion induced damage, acidizing, solvent injection, etc. Thermally induced formation damage mineral transformationsmineral and formation dissolutionwettability alterations Biologically induced formation damage issues Formation damage issues peculiar to the drilling and completion of horizontal wells in heavy oil producing zones.

This paper provides a general overview of many of the potential types of formation damage which drilling, production and reservoir engineers as well as geologists and geophysicists should be aware of when planning exploitation programs for heavy oil plays.
Investigation of the Asphaltene Precipitation Process from Cold Lake Bitumen by Confocal Scanning Laser Microscopy
Authors: Li Hongqi , Wan W. K.
Published: December 2007

The equilibrium asphaltene particle shape, size and size distribution were investigated by Confocal Scanning Microscopy (CSLM). Using CSLM, better quality images of asphaltene particles were obtained. The 3-D reconstruction from 2-D images capability of CSLM was used to visulaize the shape of the asphaltene particles. They were found to be highly non-spherical. With the CSLM operating in the fluorescence mode using incident light of 586 nm, it was found that freshly precipitated asphaltene particles gave strong fluorescence. However, if the sample was exposed to air, the fluorescence intensity quenches over a period of 24–48 hours indicating chemical changes, possibly oxidation, was taking place. Contrast to this, in a dry nitrogen atmosphere, the asphaltene particles maintained their fluorescence over the entire period when the experiment was carried out. Fluorescence emission by asphaltene particles provides yet another alternative for its size and size distribution determination especially for samples with a dark background. Imaging of such system would be less dependent on the incident light intensity. Asphaltene samples prepared at the industrially more relevant low bitumen to solvent ratios are being investigated by this method.
Sustaining the Viability of the UKCS in the New World Environment
Authors: Kemp Alexander , Stephen Linda
Published: December 2007

This paper examines the issue of how the viability of activity in the UKCS may best be maintained in the context of the new world environment. This environment is personified by (1) continued relatively low but volatile oil prices, (2) keen competition among producing countries with OPECs market power considerably reduced, (3) strong, global competition for investment funds with much of the world including the FSU now attempting to attract private investment, (4) modest oil demand growth, and (5) increasing environmental concerns and associated regulatory pressures. These features will be illustrated.

Activity in the UKCS is likely to continue to take place within this context over the next few years. How can a mature province best adapt to this environment? Considerable opportunities are still available because the actual and potential reserve base is still attractive. To maximise the opportunities appropriate actions are required by all players. Government should attempt to ensure that (1) regulations do not add unnecessarily to costs nor delay projects, (2) taxes do not inhibit projects (3) agreement and relations with other countries (including EU) take into account the needs of the UKCS and (4) R and D in the petroleum sector is fostered Appropriate Government behaviour can reduce the perceived political risks. Examples where Government initiatives are desirable will be given.

Oil companies and the major supply and contracting companies will continue to have competing calls on their limited budgets. Success in the UKCS will depend upon continued innovations in both technology and managementVwork practices, particularly directed towards cost reduction. The continued role of CRINE (with the associated technique of partnering in particular) will be discussed. The issue of how innovations and cost reducing techniques developed in the North Sea can be deployed elsewhere will be raised.
Captain Innovative Development Approach
Authors: Etebar S.
Published: December 2007

The paper will describe how a field discovered in 1977 moved from being an unattractive prospect, to the top of the Texaco North Sea UK Company portfolio by the twin drivers of new technology and a fresh look at development strategy leading to reduced development costs.

Although it was expected from an early stage that there was significant (approx. 1.5 billion bbls) oil in place, the reservoir characteristics were such that recoveries were anticipated to be low, and early conventional development plans called for over 200 development wells in more than 10 drilling centres. Unconventional thinking, an extensive appraisal programme and an extended well test in 1993 demonstrated that the field could be exploited using 6000ft horizontal wells and electric submersible pumps (ESP).

In parallel to the appraisal programme, the engineering and construction industry were solicited for ideas on how best to develop the first phase of the field. Three concepts were selected for front end engineering by three different contracting groups. The effort resulted in three different designs that were competitively tendered.

A phased economic development plan was devised to minimise drilling and facilities costs. Company sanction and final development option selection took place in the Autumn 1994 and detailed engineering began in October of the same year.

First oil is scheduled for late 1996, with revenues generated from the first phase to be used to develop a second area of the field at the end of the century.
The Feasibility and Construction of the Landfall at the Liverpool Bay Development, Point of Ayr, North Wales
Authors: Smith Michael
Published: December 2007

This paper describes the feasibility and construction of the landfall of a 20" gas pipeline and two 3" piggy-backed condensate pipelines at Point of Ayr, North Wales from BHP Petroleum's Liverpool Bay Development.

The 4,340 metre long pipeline was constructed from pipeslrings, each approximately 600 metres long using a construction site at Point of Ayr. The pipeslrings were pulled into position by the bottom pull technique using an 800 tonne capacity winch spread on a marine barge.

On completion of the pulling operation the pipelines were buried in the seabed using a submarine trenching machine operated from two work barges. The utilisation of the TM4 trenching machine was in preference to an extensive dredging and backfill operation.