bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drilling Fluid Programmes Can Reduce Hole Erosion And Minimise Hole Problems: Case Histories Offshore Vietnam
Authors: Twynam AJ , Collins PM , Jackson MD , Forman P 
Published: December 2007

AJ Twynam, PM Collins, MD Jackson, P Forman

Abstract
This paper describes technical studies undertaken at BP Exploration Technology Provision Centre and the application of these studies along with transfer of best practice and local knowledge to solve two specific problems encountered in drilling offshore Vietnam.Hole instability in shallow clastics: hole problems related to drilling shallow claystone sections with water based muds were being encountered; tight hole, bit balling, stabiliser balling, overgauge hole. This was causing lost time and increased costs. A technical audit involving the BPX Technology Provision Centre, Dowell IDF and BP Vietnam along with technology transfer from the North Sea Operations allowed the drilling fluid used on the problem section to be modified/optimised resulting in much improved drilling efficiency.Hole erosion in deeper clastics : the hole erosion encountered in deeper clastic sections of wells can lead to several problems, namely the failed attempts to secure adequate wellbore evaluation information in the reservoir section. Cores were available from problem formations and these were used in geomechanical and chemical analysis to ascertain the cause of the problem. Based on the findings it was possible to make recommendations to the drilling fluid programmes and drilling practices, which have lead to enhanced drilling efficiency and much improved wellbores.

Introduction
BP Exploration commenced drilling offshore Vietnam in December 1992 operating in Block 5.2, 6 and 118. Several technical challenges were experienced in the drilling of these wells, In an attempt to optimise on drilling performance, several studies were undertaken. This paper details two such studies undertaken by the BP Technology Provision Centre in Sunbury, UK. The first study was to carry out a technical audit on drilling fluids being used in an attempt to improve drilling performance in shallow clastic formations. The second study concerned the observed problem of washed out holes in the deeper clastic formations which had resulted in problems with adequate formation evaluation, This paper describes the problems as identified, the methods used to determine the cause of the problems and discusses the conclusions and recommendations resulting in improved performance.

HOLE INSTABILITY IN SHALLOW CLASTICS
One of the more problematic hole sections on wells in Vietnam (excluding the loss control problems in the carbonates) is the 17" /17-1/2" section through the shallower clastics. These sections were originally drilled using a gel/CMC system which was gradually upgraded to a KCL/Polymer (PHPA) system.
Problems encountered on this section were due to water base mud" being used to drill shallow clay stones. (Bit balling, tight trips, reaming, shaker blinding, stabilisers caked up). This was leading to expensive mud bills, compromised drilling performance and poor quality hole.
Technology Leading the Way to Mukhaizna Heavy Oil Development
Authors: Lievaart L. , Al Hinai K. M. , Al Khabori K. J. , van Wunnik J. , Masson D. , Al-Kindy I. H. , Mul P. J. 
Published: December 2007

Abstract
Mukhaizna was discovered in Central Oman in 1975. The field contains large volumes of 15° API crude (STOIIP 375 mln m3, in situ viscosity 1700 mPa.s). During the mid 80's it was established that production rates from initial vertical wells were marginally economic, both primary and on steam soak. In recent years the introduction of new technology, especially the drilling of horizontal wells, has significantly advanced the fields potential for commercial development:
A pilot project using five 1000 m long horizontal wells was started in August 1992. The wells were produced with progressive cavity pumps, with production being trucked to a production station at 60 km distance. Productivity improvements of a factor 4 over (cold) vertical wells were obtained. The project demonstrated that owing to the high pore compressibility of the shallow, unconsolidated Gharif reservoir rock, associated with grain crushing, and the field-wide presence of a Middle Gharif shale, satisfactory primary recoveries of 100,000 m3 or more can be obtained from horizontal wells at acceptable (lateral) distances to the oil-water contact.
Theoretical studies and numerical simulations have shown the dry individual well recoveries to increase proportionally with increasing distance to the oil-water contact, Reservoir performance during dry production is characteristic of increasing pore compressibility with increasing rock stress. Significant hysteresis is observed between the increasing and decreasing rock stress cycles. Core plug measurements and pressure recordings in a dedicated observation well have served to validate the results of the modelling study. Based on the results of the pilot, the fields expectation ultimate recovery was increased from 5.3 to 11.0 mln m3.
As a next step towards full field development, a strategic development project has been formulated aimed at narrowing down remaining uncertainties with respect to reservoir performance. Production from ca. 10 horizontal wells will commence in 1996, Dedicated early production (satellite) facilities will be used, to which the oil will be evacuated with admixed water through a 30 km, large diameter pipeline under downhole pump pressure. The current project planning basis includes a number of technology applications aimed at increased cost effectiveness, such as a revised casing scheme, alternative subsurface pumping systems with high output pressure rating, coriolis flow meters and telemetry, Targetting of the additional project wells will be based on a 3D seismic survey acquired during the second half of 1994.
Following a successful project, Ml field development may proceed early in the next century.
A Proposed Dynamic Model for Foamy Oil Properties
Authors: Sheng J. J. , Hayes R. E. , Maini B. B. , Tortike W. S. 
Published: December 2007

Abstract
To simulate foamy oil flow, it is first important to calculate foamy oil properties properly. Several previous investigators have made such an effort. However, their approaches do not account for the time (or rate) dependent changes in foamy oil characteristics. This paper proposes a methodology for including the dynamic processes in the calculation of foamy oil properties, using molar variables. The issues of bubble nucleation, growth and decay are also reviewed and discussed.
The basic foundation of this model rests on the theoretical results and experimental observations of nucleation, bubble growth and decay. The model is verified by matching the calculated results with experimental data.
The results calculated from this model show how the foamy oil properties vary with pressure and time. The non-equilibrium processes of both bubble growth and decay are important for the calculation of foamy oil properties. However, the rate of decay for the entrained gas is most significant in foamy oil flow.
This method of calculating foamy oil properties provides the basics for developing numerical simulation models of foamy oil flow. The results from this model may also be useful for well testing analysis in foamy oil reservoirs.
Economic Field Development in Venezuela Heavy Oil Fields Using Multiphase pumping Technology
Authors: González Rubén , Guevara Emilio 
Published: December 2007

Abstract
Multiphase pumping is a technology in fair development and usage in the oil industry. The multiphase transport of oil, gas and water produced in offshore and onshore fields, and/or at long distances from the production units is not longer an impossibility or a non profitable enterprise. Therefore, the exploitation of marginal fields or those located at long distances, as well as new developments, are about to become a feasible reality.
The exploitation of heavy oil fields in Venezuela is, more than ever, the future of the oil industry in this country, since its is very well known that more than half of the world total heavy and extra heavy oil reserves are located in Venezuela.
Studies on the technical and economical feasibility of the application of Multiphase Pumping are being carried out by INTEVEP, S.A. together with the operating affiliates of PDVSA, aiming, at testing and consolidating this technology with minimum investment and reduction in production costs. One of these surveying studies was performed for the ARECUNA FIELD of CORPOVEN, S.A. located in the Orinoco Oil Belt. The reduction of investment and production costs in substituting traditional flow stations for handling heavy and extra heavy oil by a multiphase pump was focused.
The objectives of the paper is to present the technical and economical conclusions of the above mentioned feasibility study, and the performance and operational experience obtained with a twin-screw multiphase pump during five months of field operation.
The Commercial Potential of Steam Assisted Gravity Drainage
Authors: Donnelly John K. , Chmilar M.J. 
Published: December 2007

John K. Donnelly* and M. J. Chmilar

Abstract
Steam Assisted Gravity Drainage (SAGD) is the key to the economic exploitation of over 40 billion barrels (6.35 × 109 m3) of bitumen from the McMurray formation. The SAGD technology has been proven in two stages of piloting and is ready for commercial application. Engineering and economic studies indicate that the SAGD technology can be applied at a unit cost that is substantially below the market price for bitumen which has been at an average often dollars per barrel at the field gate over the last few years.
Based upon the premise that SAGD recovery is feasible throughout the Athabasca area, in reservoirs whose quality equal or exceed that found at the SAGD pilot site, an evaluation study was undertaken. The objective of the study was to map projected bitumen recovery and steam oil ratio as determined for a conceptual commercial SAGD recovery scheme.
The study applied geological and engineering criteria based on current projections of SAGD performance and a conceptual commercial recovery scheme, to analytically derive predictions of cumulative steam oil ratio (CSOR) and bitumen recovery. The study involved evaluating models for estimating SAGD CSOR and bitumen recovery; applying the most suitable model to generate CSOR and bitumen recovery predictions using screened geological data from an Athabasca well data base; then plotting contour lines representing the predicted CSOR and recovery values on a surface map of the Athabasca deposit. The contoured maps outline areas where it is expected that a CSOR of 3.5 m3/m3 or less and a bitumen recovery of greater than 10,000 cubic meters (63,000 barrels) per hectare which is equivalent to an average bitumen production rate of 250 barrels (40 m3) per day over a five year well life from 800 meters long well pairs spaced 90 meters apart.
The maps highlight locations in Athabasca where the best reservoir performance would be expected and delineates the areas which should be studied in detail for commercial application of the SAGD technology.
P. 295
Stresses and Displacements Around Hydraulically Fractured Wells
Authors: Wood D.B. , Junkin George 
Published: December 2007

Abstract
The stress and displacement fields around hydraulically fractured wells have been calculated. These calculations, which are based on the linear theory of elasticity for homogeneous isotropic media, lead to two useful conclusions:
1. Hydraulic fracturing significantly changes the stress state around the well, removes the stress concentration caused by the wellbore, and reduces the maximum compressive stress in the rock matrix.
2. If a small fraction of the near wellbore region of a fracture is left unpropped, the fracture will close at the wellbore due to elastic deformation of the unpropped rock.

Introduction
This paper deals with two questions related to the application of the widely used well stimulation technique, hydraulic fracturing:
1. Does hydraulic fracturing remove the stress concentrations which exist due to the presence of the wellbore and the perforations? perforations?
2. How much of the near-wellbore region of the fracture can be left unpropped without the potential stimulation of the well being lost?
It is convenient to consider these two questions in the same paper because they can both be analyzed with the same theoretical calculation.
In some deep, abnormally pressured wells, it is necessary to limit the drawdown to avoid producing formation fragments caused by the producing formation fragments caused by the failure of the rock due to the very high stresses induced near the wellbore. These high stresses occur because of the borehole and the perforations. Hydraulic fracturing can decrease the stress around the wellbore by increasing the productivity index of the well and reducing the drawdown necessary to obtain a given production rate.
Development of Heavy Oil in Liaohe Oil Field
Authors: Tiejun Dun , Qingshan Tang 
Published: December 2007

Abstract
The Liaohe oil field, which is buried at a depth of about 1000 m, has abundant amount of heavy oil. With thermal development by steam injection, it is the most productive heavy oil field in China.
In this paper, the observation of lithological and mineralogical change in the process of steam injection is discussed. Significant dissolution caused by water/rock interaction was observed for the minerals such as quartz and feldspar in the clastic reservoir rock. This caused changes within the pore structure in the rock. A computer program to predict the dissolution loss and precipitation of various minerals in water-rock reaction has been developed. The mechanism of steam displacement is also investigated.
Advanced Process Control Of Extraction: Sensors And Models
Authors: Kresta Jim 
Published: December 2007

Jim Kresta

Abstract
Process Control of the Hot Water Extraction Process is still relatively limited, largely because critical process measurements have not been available. Over the last few years, Syncrude has been endeavouring to address this through the development of process specific sensors. Recent implementation of these sensor developments is providing a new look at the process and offers a cost effective route to improving process operation.
This paper will describe recent advances in Extraction on-line process measurement systems; the oil sand analyzer, froth quality meter, and gamma spectrometer. These instruments allow us to examine for the first time, the short-term effects of variability in oil sand ore and process conditions on bitumen recovery and product quality.
An understanding of the relationships among incoming ore, processing conditions and product parameters is required to optimize the Extraction process. Multivariate data analysis techniques are allowing us to examine these relationships in detail and will provide the basis for an improved process control strategy. Some of these relationships are examined and their implications discussed.

Introduction
Producing Syncrude Sweet Blend (SSB) is a three stage process of mining oil sand, extracting bitumen from the sand and upgrading the bitumen. In the extraction process, oil sand ore is conveyed to the tumbler where it is conditioned with steam, caustic, hot water and mechanical energy. The resulting slurry is fed to the Primary Separation Vessel (PSV).
P. 611
Visualization of Deformation in Unconsolidated Athabasca Oil Sand
Authors: Leung S. K. , Kry P. R. , Wong R. C. K. 
Published: December 2007

Abstract
Dense unconsolidated Athabasca oil sand exhibits significant dilation in triaxial compression tests at low confining stresses of 5 to 750 kPa. This paper presents an innovative method which can visualize and calculate the porosity distribution in a sheared sample.
Thin sections from the sheared sample were made to quantify the porosity within and outside the shear zones. Porosity was determined using image analysis on back scattered scanning electron microscopy (SEM) images of the thin sections. These porosity data were used to calibrate computer assisted tomography scan (CAT scan) images of the whole core sample so that the porosity distribution in the sheared sample could be mapped. The calculated average porosity of each of the four samples agreed very well with porosity measured by Dean-Stark analysis.
In the CAT scan images, shear dilation was seen to be concentrated along and within multiple, localized shear bands. However, the porosity distribution within each sample had a very narrow range compared to the overall increase in porosity, implying the sheared samples were essentially uniformly dilated.
Design, Preparation, and Operational Aspects of the First Horizontal Subsea Trees Installed from a Jack-Up
Authors: Ferguson R. A. , Stewart D. R. , Holland B. , Thompson A. 
Published: December 2007

Abstract
The Johnston Gas Field lies in blocks 43/26a and 43/27 of the UK sector of the Southern North Sea, 11 km to the Northeast of the Ravenspurn North production platform (Figure 1). The water depth at this location is approximately 145 feet. The field was discovered in April 1990 by the 43/27-1 well and successfully appraised in July 1991, by the 43/26a-8 well.
The field (Figure 2) is formed by a structural trap bounded to the Southwest by a NW-SE trending fault and by structural dip to the north and east. The reservoir itself comprises Permian Lower Leman sandstone exhibiting excellent porosity and permeability characteristics. Recoverable reserves are estimated to be in the range of 155 to 195 BCF. The gas sales contract requires a DCQ of 53 MMSCF/D for a six year plateau, with a peak rate of 90 MMSCF/D. Two wells located near the crest of the structure satisfy the production contract requirements, however a third well may be required in the third year of production. The overall field life is expected to be 13 years.
This paper describes the selection, design and installation, in this field, of the first horizontal subsea trees to be installed from a jack-up.
Multi - Platform Drilling Operations Utilising One Rental Top Drive - The Commercial and Technical Benefits
Authors: King Ian M. , Douglas David 
Published: December 2007

Abstract
The introduction of the top drive into the international drilling market constituted one of the industry’s major technological advances during the 1980’s. One disadvantage of the conventional top drive is the rig modifications necessary to support the torque generated, particularly on drilling units equipped with masts. In an effort to alleviate this disadvantage, an integrated drilling system (IDS) has been developed, utilising a torque tube in place of the normal fixed rails. The impact of introducing an overhead drilling system into an operating drilling unit has therefore been greatly reduced.
This paper will focus on the benefits of one such application in the northern North Sea. It will stress the technical and commercial benefits seen by the Operator and concentrate on the portability of the system, allowing one rental IDS to be utilised on more than one platform. By employing the IDS the Operator has been able to efficiently upgrade the platform rigs and drill extended reach wells which may not otherwise have been possible.
This paper will conclude that a rental overhead drilling system is a viable option to meet the changing demands of drilling programs in mature basins.
Changes to Regulation of Drilling and Workovers in UK Sector by Removal of Prescription
Authors: Powell T. A. F. , Dobson J. D. , Dykes C. E. 
Published: December 2007

Abstract
The regulation of the United Kingdom's offshore oil and gas industry is undergoing radical restructuring, abandoning the traditional prescriptive approach. The final part of the restructuring programme is to introduce a non-prescriptive regime for drilling and other well operations. In future, the safety of drilling and well operations in UK waters will be enforced through review of a combination of safety cases and notification of well operations, backed up by a programme of inspections and audits. The regime will be supported by goal setting regulations which establish performance standards for wells and well operations.
J Block Drilling Operations: Continuous Improvement leads to Record Performance
Authors: Parry N 
Published: December 2007

ABSTRACT
Phillips Petroleum Company United Kingdom Limited has recently completed drilling 17 development wells on the Judy and Joanne Fields (J Block) in Block 30/7a. Twelve wells were drilled at the template/platform location using the jack up "Galaxy", and 5 wells were drilled at the subsea manifold location using the jack up "Magellan".
A clear record of continuous improvement has been demonstrated. Drilling performance shows a steady increase in penetration rate (overall feet per day) over the project. Perhaps the most visible indicator of this has been in 1214" hole. The maximum footage drilled in a 24 hour period has increased from 3600 feet on the first well, PI, to a world record 8631 feet on well P11.
All the team involved in the operation, Phillips, drilling contractor and service company personnel both onshore and offshore, have contributed at some point to achieving this success. This paper discusses the many innovations, equipment improvements and procedural changes that have led to this steady increase in overall feet per day.
Geological Steering Assists Cost Effective Exploitation of Marginal Reserves
Authors: White J. 
Published: December 2007

Abstract
Carefully positioned horizontal wells are helping to maximise recoverable reserves from both new and mature North Sea producing fields. In many cases, the economic performance of these wells is very sensitive to position within the reservoir. For example, displacing the horizontal section in some reservoirs by five or ten feet TVD is sufficient to significantly change the asset value of the well.
To achieve ideal drainhole positioning, the surrounding formation must be sensed while drilling, and the hole trajectory modified accordingly. This geological steering, or geosteering, becomes particularly important when targets are small and the exact geometrical position of the target cannot be accurately determined from surface seismic or offset well data.
Drilling horizontal wells to almost pinpoint accuracy relative to surrounding geology has tremendous potential to unlock otherwise uneconomic reserves of oil and gas. The steering techniques reviewed in this paper are central to this process, and represent a new and challenging role for multi.disciplined field development teams in the coming years.
Preparing for Decommissioning of the Heather Field
Authors: Hustoft R. , Gamblin R. 
Published: December 2007

Abstract
This paper presents some of the issues which have influenced the decommissioning planning for the Heather Field facilities. The paper is based on the results of conceptual and pre-engineering work performed to date, and covers the following: –brief background on the Heather Field development and production history, field facilities, and achievements in extending field life to date,–considerations and constraints which have shaped Unocal's approach to the planning of the Heather Field decommissioning project, and–discussion of the stages to be undertaken in performing the decommissioning of the field facilities, concepts and options which exists for these stages, and operational and technical considerations applicable to each stage. The stages addressed include engineering and planning, well plugging and abandonment, topside systems cleaning and preparation for removal, pipelines decommissioning, topside facilities removal and disposal, and platform structure removal and disposal.