bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Drilling Dynamics System Closes the Model-Measure-Optimize Loop in Real Time
Authors: Chen David C-K , Smith Mark , LaPierre Scott 
Published: December 2007

Abstract
This paper presents a newly developed "intelligent" system designed to avoid resonance and to reduce vibrations. The system integrates real-time BHA dynamics software and realtime downhole vibration data to provide accurate modeling results and data analyses. Unlike conventional BHA dynamics software that is run for well planning or post-run analysis, this system uses real-time data (e.g., WOB, inclination, DLS) to produce real-time updates of critical rotary speeds. The updates are then displayed along with the rotary speed to show if the rotary speed is too close to one of the predicted critical rotary speeds. In addition, the modeling results can be compared with actual real-time downhole vibration data to corroborate the actual downhole condition. Field data have shown that the new system is effective in identifying the vibration mechanism and avoiding harmful vibrations.
Risks Assumed in Drilling Contracts: Global Comparison and Case Histories
Authors: Foster Stephen J. , Gibbie Karl W. , Mason Daniel C. , Baron Sheila L. 
Published: December 2007

Abstract
Drilling contracts are put to their test when a well blows out, workers are killed or injured, equipment is lost in the hole, third-party claims are made against the Contractor or Operator for injuries or damages, or other calamities occur. It is the liability and indemnity terms within these contracts that become a focal point when such mishaps take place. As the activities of Operating and Contracting Companies expand to all parts of the world, Risk Managers are assessing risks under many different drilling contract forms. Every drilling contract will specify, to varying degrees, the responsibility of the parties (Operator or Contractor) for costs and the liability of accidents or losses. The reasonable and acceptable allocation of risks assumed by the Operators or Contractors in a given contract is essential to managing risks successfully.
This paper details the similarities and differences in the contractual risk allocation features of a number of Daywork Drilling Contracts selected from the major drilling areas around the globe. Numerous global contracts will be analyzed in conjunction with actual drilling case histories to illustrate the application of the language and terms under differing contract risk allocations. This information can provide a tool to assist in contract negotiations for assessing the risks and identifying which risk each party is willing or not willing to bear.
The Chad Project Drilling Start-Up… High Performance Expectations in a Remote Area
Authors: Roberts C. M. , Breeding D. L. 
Published: December 2007

Abstract
Between March 2001 and November 2002, drilling operations for the Chad development underwent start-up. Three purpose-built drilling and two completion rigs were delivered from Houston to the field location, assembled, accepted and put into service. Over 3000 tons of materials and supplies were shipped from worldwide fabrication and assembly yards; this material crossed oceans to the west coast of Africa and traveled more than 1000 kilometers by rail and/or truck through two countries to arrive in time for startup. An 850 person camp and more than 150 thousand square feet of warehouse and service space were constructed and occupied. A team of 2250 people was assembled; more than seventy percent of the team is made up of residents of Chad hired during and just prior to the start-up.
This paper provides an overview of the drilling aspects of the project behind the start-up, describes the socioeconomic framework within which the teams were assembled, and discusses the approaches and experiences of the team members as they made the efforts necessary to achieve the start-up in the remote country of Chad.
Optimizing the Cement Sheath Design in HPHT Shearwater Field
Authors: Ravi K. , Bosma M. , Hunter L. 
Published: December 2007

Abstract
The need for a fit-for-purpose cement sheath was recently emphasized in the HPHT Shearwater Field when annular pressures were observed on all but one of the production wells, either immediately or during the completion phase. Such annular pressures may result in an inability to produce the reservoir, which fully erodes the value of the asset.
The main objective of a primary cement job is to prevent formation fluids from migrating into the annulus so that the reservoir can be produced safely and economically. To achieve this objective, as a first step, cement slurry should effectively displace the drilling fluid in the annulus. The set cement sheath should then withstand the stresses induced by the well events and maintain integrity during the life of the well.
For the Shearwater Field, a rigorous design method was used to evaluate the integrity of the cement sheath as a function of its properties and formation characteristics. The design procedure was based on finite element modeling and simulated the sequence of events starting from the drilling phase, including cement hydration, well completion, and production.
This paper discusses ways to improve cement designs in the Shearwater Field. The methodology developed was used to optimize the design of future Shearwater wells, resulting in the specification of improved cement systems/methods. The criteria used to evaluate the cement sheath performance are discussed, as well as the effects of well events on cement systems for reducing the risk of damage.
The specification from this analysis was implemented in the field, and the optimized cement sheath withstood the stresses from well completions and other events. The new well is on production and all indications are that no annular pressure problems exist. Therefore, this design process can help improve the economics of constructing and producing oil and gas wells, resulting in a cost-effective life-cycle design.
The process can also reduce health, safety, and environmental (HSE) risks because it minimizes the potential for zonal isolation failures.
Characteristics of Microgels Designed for Water Shutoff and Profile Control
Authors: Feng Yujun , Tabary René , Renard Michel , Le Bon Christel , Omari Aziz , Chauveteau Guy 
Published: December 2007

AbstractTwo microgel samples were prepared by crosslinking an acrylamide-based terpolymer solution with a non-toxic zirconium crosslinker under controlled shear flow. The characteristics of these two microgel samples were determined by using different laboratory techniques in order to evaluate their performances for water shutoff or profile control operations. The microgel size was measured by Photon Correlation Spectroscopy (PCS) in dilute regime and at small scattering vector. As predicted by our theoretical model, microgel size decreases as the -1/3 power of applied shear rate. The size of these microgels is almost independent of pH, salinity and temperature in the domain investigated. Their mechanical and thermal stability is also satisfactory. In addition, such microgels can be easily injected into porous media without any sign of plugging. All these results suggest that these microgels should be good candidates for water shutoff and profile control operations. However, a further investigation is required to optimize their preparation to obtain the desired properties for a given application.
Novel Scale Inhibitor Polymers with Enhanced Adsorption Properties
Authors: Davis K. P. , Fidoe S. D. , Otter G. P. , Talbot R. E. , Veale M. A. 
Published: December 2007

Abstract
A new range of polymeric scale inhibitors has been developed combining exceptional scale control activity with enhanced adsorption properties. The polymers are stable up to at least 200ºC and have high activity against barium sulphate and calcium carbonate scales. By incorporating novel end-capped technology, it is now possible to produce scale inhibitors with improved adsorption properties which provide significantly extended squeeze lifetimes relative to conventional technology.
PWRI: Scale Formation Risk Assessment and Management
Authors: Mackay E. J. , Collins I. R. , Jordan M. M. , Feasey N. 
Published: December 2007

Abstract
The injection of seawater into oilfield reservoirs to maintain reservoir pressure and improve secondary recovery is a well-established, mature, operation. Moreover, the degree of risk posed by deposition of mineral scales to the injection and production wells during such operations has been much studied. However, the current drive within the North Sea to reduce the environmental burden of production chemicals and to reduce oil discharge to the environment has focused attention on the challenge of produced water management and has introduced new challenges for scale management involving produced water re-injection.
This paper will outline the risk assessment process required prior to undertaking produced water re-injection. The factors that will be considered are the location of scale deposition around fractured and unfractured injection wells, formation damage potential and impact, and retardation effects on injected scale inhibitors.
The paper will draw upon computer modelling techniques, laboratory generated coreflood data, and field results that will demonstrate the impact of the following factors on long term water injectivity: viz, scaling tendency, suspended solids content, suspended oil content, injection temperature, reservoir type, and completion type. Furthermore, scale control measures currently being employed (e.g., scale inhibition, hydraulic fracturing, drag reduction, and solvent cleaning) will be assessed and reviewed against the risks identified. Finally, this paper will outline in detail the particular scaling issues associated with produced water re-injection for both platform and subsea facilities.
Development of a Novel Water in Oil Microemulsion Based Scale Inhibitor Delivery System
Authors: Miles A. F. , Bourne H. M. , Smith R. G. , Collins I. R. 
Published: December 2007

Abstract
Water in oil (w/o) formulations containing a range of scale inhibitors have been prepared for squeeze application. Depending on their composition these have been found to be either microemulsions or weakly structured mixtures.
A particular feature of the materials described is the type and concentration of surfactant used. High concentrations of surfactants are traditionally required to generate and stabilise conventional microemulsions. However, the back-production of the surfactants following a squeeze may cause undesirable process upsets. To minimise these upsets and to maximise the performance of the delivery technique, novel complexing agents, which, when combined with suitable scale inhibitors, form semi-stable species capable of stabilising w/o systems have been developed.
A detailed investigation of the properties of selected materials has been performed and experimental measurements including phase behaviour, reservoir condition coreflood tests and inhibitor desorption data are presented. A new technique which provides data in-line with core performance tests is also described.
The possibility to utilise the phase behaviour of these materials to increase squeeze life is also explored. Data for Miller Field conditions, showing an increase in squeeze life, are presented.
Conditions For Scaling In Pipelines – Ph In Glycol Solutions
Authors: Seiersten Marion , Dugstad Arne , Gulbrandsen Egil 
Published: December 2007

Abstract
If a glass electrode calibrated in aqueous pH standards is used to measure H+ concentration in aqueous glycol solutions the result will be in error due to the large change in solvent properties. Based on strong acid – strong base titrations in glycol solutions it is possible to calibrate glass electrodes. The titration does not only give the calibration constant for the electrode, but also the autoprotolysis constant for the solvent can be determined. The calibration method makes it possible to determine acid constants in glycol by potentiometric titration.
Barium Sulphate Precipitation In Porous Rock Through Dispersive Mixing
Authors: Woods A. W. , Harker G. 
Published: December 2007

Abstract
We describe the reaction which occurs when formation fluid containing Ba in solution is displaced by and mixes with injected water, containing sulphate, to form BaSO4. The model is based on the conservation of mass of both the barium and sulphate, assuming that each species is advected with the flow, and that at the interface between the two fluids, dispersive and diffusive mixing of the fluids leads to precipitation. The model equations are solved numerically, and a simple asymptotic model for the reaction, valid at long time, is developed. This identifies that in a linear geometry, the mass of solid which forms when the front has distance x from the source, decays at a rate proportional to 1/x½. The modelling approach may also be used to describe injection into a radial geometry, leading to an analogous asymptotic model for the decay of solid precipitate with distance from the injector well.
Scale Formation in Iranian Oil Reservoir and Production Equipment During Water Injection
Authors: Moghadasi J. , Jamialahmadi M. , Müller-Steinhagen H. , Sharif A. , Ghalambor A. , Izadpanah M. R. , Motaie E. 
Published: December 2007

Abstract
This paper presents the mechanism of scale formation by water in oil fields and suggests an accurate model capable of predicting scaling phenomena in Iranian Oilfield operations due to mixing of incompatible waters or change in thermodynamics, kinetics and hydrodynamic condition of systems. A new and reliable scale prediction model which can predict scaling tendency of common oilfield water deposits in water disposal wells, water-flooding systems and in surface equipment and facilities is developed and present. The development of the model is based on experimental data and empirical correlation, which perfectly match Iranian oil fields conditions. Furthermore the simultaneous deposition of oilfield scales and competition of various ions to form scale which is common phenomena in oil fields are reflected in the development of the model allowing the effect of each scale on the others to be taken into account. The new model has been applied to investigate the potential scale precipitation in Iranian oilfields, either in onshore or offshore fields where water injection is being performed for desalting units’ water disposal purpose or as a method of secondary recovery or reservoir pressure maintenance.
Rejuvenation of Matured Oil Fields in South Sumatra, Indonesia
Authors: Aprilian Salis , Kurnely Kun , Novian Kiagus 
Published: December 2007

Abstract
Pertamina DOH SBS located in South Sumatra, Indonesia, operates the largest area of oil fields under Pertamina own operations. It has 55 fields mostly discovered and developed fifty years (even for some more than a hundred years) ago. The common problems encountered in the old oil fields are lack of data; old facilities; artificial lifts requirement, depleted in pressure and reserves; and high water cut problems.
This paper reviews a comprehensive study on rejuvenation of the matured fields in Pertamina DOH SBS by employing a cross function synergy team (multidiscipline team) and project management approaches. The teams consist of geophysicists, geologists, reservoir engineers, operation/ production and facility engineers, and professionals from supporting department such as finance, logistics, HSE, HRD, IT, etc. The project called Production Enhancement Projects (PEP) was established in 2001 and divided into phases.
The first phase of PEP that was assessing detailed subsurface and surface facilities data has been done successfully resulting in 45.6 MMBO of additional oil reserves within 12 selected existing matured fields. Besides, the upside potentials are identified as a surprising spill over of the study.
Plan of further development for each field has been proposed including the evaluation of economics and environment aspects by considering in-depth GGRP (geophysic-geology-reservor-production) study and intensive discussion among team leaders, team members, and management. After prioritizing the proposed work plan, several implementations of well work (such as: reopening; re-perforating; reparation; sidetracking, twin drilling; etc.) show some successful results. At least two wells will be drilled this year (2002) to prove the upside potentials of oil located in deep zones of the existing fields.
An Integrated Sand Control Method Evaluation
Authors: Samsuri Ariffin , Sim S. H. , Tan C. H. 
Published: December 2007

Abstract
A numerical model has been developed that is able to predict the onset of sand production and evaluate the performance of sand control, should sand production becomes unavoidable. The simulation of perforation stability was carried out first using a two-dimensional, two-phase finite-element model. This is a coupled geomechanical and fluid flow model. The rock was assumed to be heterogeneous and the pores were completely filled with fluid. The deformation condition is considered as plane strain and either the Mohr-Coulomb or Drucker-Prager yield surface was used to designate perforation failure. The model enables the study on the effect of perforation pattern and density on wellbore stability. Simulation runs on a sample model indicated that the lowest pore pressure, the greatest shear stress and minor principle stress were found close to the perforation tip. The greatest major principle stress occured around the center of perforation roof. In other words, the perforation was always surrounded by high stress concentration. In those events when sand production is a certainty, it is necessary to evaluate the performance of sand control methods to be used. A finite-difference flow model was used to calculate the additional pressure drop from the well boundary to the sand control screen. The Forchheimer equation was used in place of the more conservative Darcy equation so that the effect of high-velocity flow to the well performance could be considered. The result of several sample runs indicated firm relationship between total additional pressure drop and the flow rate imposed, where a larger flow rate will cause greater pressure loss. Also, the well productivity showed improvement with more shots per foot. The results suggested that the majority of well pressure drop was caused by the casing-cement tunnel.
Improved Oil Recovery through the Use of Horizontal Well in Thin Oil Column: A Case Study from Platong Field, Gulf of Thailand
Authors: Maroongroge Vichai , Sandarusi Kamal A. , Schmalz Arlen , Schut Gerard , Nucharoen Panaratn 
Published: December 2007

Abstract
This paper presents a case study of analysis that leads to the decision to drill the first horizontal oil well (G-21) in the Platong field in the Gulf of Thailand. The application of horizontal well technology in this field is a challenge because of low seismic resolution, small-sized reservoirs, and stacked reservoir systems. Successful use of horizontal well technology requires an integrated team approach that incorporates all available data to justify a business case for drilling the well.
The 37B sand in the Platong field has a 30-foot oil column, a small gas cap and a large underlying aquifer. Well G-18 is a vertical producer in the 37B sand that penetrates the oil column and aquifer with only 11’ of net pay. The well has produced over 500MSTB. However, because the completion lacked a means of artificial lift, flowrates were restricted once water production began. Eventually, the well was only capable of intermittent flow. A material balance analysis indicated the minimum original oil in place (OOIP) of 4.5 MMSTB with a strong water support. This volume estimate was also supported by seismic analysis and geological correlations. A reservoir simulation study was conducted with an aim to improve the oil recovery by investigating several production strategies. Since there is a free source of CO2 gas available, an evaluation of CO2 miscible flooding was also conducted. Results show that the minimum miscibility pressure (MMP) is much higher than the reservoir pressure and miscible gas injection is not suitable for this reservoir. The presence of a small gas cap and a strong bottom water drive led to the decision to drill a horizontal well. Simulation shows that a 1,000' long, horizontal well optimally placed in the gas cap is the simplest and best strategy to recover more oil from this reservoir. The estimated incremental oil recovery is 1.2 MMSTB.
Performance results after drilling show that the well is an economic success and also proves that the same integrated team approach can be used successfully in the development of other analogous reservoirs with similar geology. The economic success of this well also shows that there is a potential for additional oil reserves in the shallow zones above the current pay window. To date, as many as 40 additional prospects have already been identified for horizontal well candidates to further the oil development for the field.
In-House Design & Modifications Improve Sour Gas Processing in an Indian Offshore Gas Field – A Case History
Authors: Shankar Ravi , Kumar Adesh , Gupta V. P. 
Published: December 2007

Abstract
BXY field is the largest gas field of India, located in offshore, 80 km from Mumbai city. The field produces about 32.5 MMscmd sour gas using two process complexes BXA & BXB. The field was put on production in September’1988 with initial gas production of about 2 MMscmd. The field attained a gas production of 10 MMscmd during 1994 and this was the period when some operational problems were observed at one of the process complexes i.e. BXA.
The sour gas processing (H2S &gt;100 ppm) at BXA involved cooling of well stream fluids (from 95 to 43 °C) in shell-tube type well stream coolers, three phase separation of well fluid and finally transportation of gas & condensate to shore terminal at a distance of about 230 km. Initially each complex was designed for lesser capacity which was upgraded to 15 MMscmd in 1995-96 after progression of field development. No problem was observed in BXB complex. In BXA complex, the processing temperature exceeded the normal temperature of 43 °C. This resulted in rising trend of moisture content in sales gas, high consumption of TEG (2-3 times more than normal value) in dehydration unit and increased load on operational staff for monitoring. Frequent failures of pipe & fittings of gas cooling system were observed. Well stream coolers had problem of air locking & cooling water flow across coolers came down to half quantity. Overall, severe operational problems were observed in the plant.
An in-house analysis was carried out to resolve these problems. The analysis of total processing system viz. gas cooling system, gas dehydration system, condensate stabilization system was made. Based on analysis, it was found that gas cooling water system is the bottleneck. The various components including material of construction of various equipment of this unit were analyzed and causes of operational problems resolved. A new cooling water system known as "cooling water segregation system" was conceived, designed and installed at BXA complex & other suitable measures undertaken. These efforts have streamlined the operating conditions of plant and are now processing 16.5 MMscmd gas without any problem.
The present paper describes stepwise identification of problems, design, review, installation of newly designed system and other issues to resolve the operational problem in this major processing complex. The improved design on implementation resulted in smooth operations in the plant and is working since then without any problem.