bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comprehensive Experimental Investigation of Drilled Cuttings Transport In Inclined Wells Including the Effects of Rotation and Eccentricity
Authors: Peden J. M. , Ford J. T. , Oyeneyin M. B. 
Published: December 2007

ABSTRACT
This paper presents the findings to date of a research project initiated to investigate drilled cuttings transport in deviated wellbores. The research programme utilises a simulated wellbore to study the mechanisms of cuttings transport in deviated wells. The cuttings transport column, has been designed to allow easy variation of well geometry in terms of annular size, deviation angle and pipe eccentricity. The column is also equipped with a variable speed motor/gear system for the simulation of drillpipe rotation.
This study has investigated the influence of a range of variables such as hole angle, fluid rheology, cuttings size, drillpipe eccentricity, circulation rate, annular size, and pipe rotation on cuttings transport efficiency using the concept of Minimum Transport Velocity (MTV). This concept presumes that a hole can be efficiently cleaned by either maintaining cuttings rolling or in suspension, if the annular velocity is equal to or greater than a minimum transport velocity for that operational condition. Thus, the lower the minimum transport velocity the easier it is to efficiently clean the hole.
The results so far have shown that depending on the level of eccentricity and annular size, fluid rheology as well as flow regime appear to have highest impact on the MTV. With low viscosity circulating fluid, turbulent flow regime seems to predominate for concentric pipes with suspension and rolling attained at low MTV. The use of high viscosity fluids appeared to improve the cuttings transport further especially at highly deviated angles. The transport efficiency is further enhanced by pipe rotation at various levels of eccentricity. Smaller cuttings appeared to be easier to remove than larger ones. There is however a small exception to this when larger cuttings were found to be much easier to remove at low angles with the use of high viscosity fluids.
The experimental results have been compared with the predicted MTV from the computer model concurrently being developed and good agreement has been observed.
Development Planning for the 1990's
Authors: Cuckson J. , Colclough J. G. 
Published: December 2007

ABSTRACT
The response of the offshore industry to the 1986 price collapse showed how flexible the industry can be when faced with unexpected challenges. In this case the challenge was met by following a "lean and mean", essentially short term view. This, coupled with a depressed market led to a marked increase in activity in the Dutch offshore sector reflected in an increased rate of development of hitherto marginal fields which are now coming on stream. The Paper takes a somewhat unusual view in questioning whether extrapolation of this approach is wise in the circumstances likely to prevail in the 1990's. Growing concern about the environment, redoubled efforts to improve safety offshore and, probably, a hardening in the prices for goods and services lead us to question whether extrapolation of the minimum facilities approach remains the most appropriate way to develop the smaller fields typical of the Dutch continental shelf.
The paper describes the present development concepts of minimum facilities platforms, mini-satellites and highly deviated wells as well as novel techniques and the advantages and disadvantages they bring with them. The role of the "soft" long term issues of manning philosophy, logistics and waste management, which play an increasingly significant role in selection of development plane, is also explored. It is shown that the planning of future developments requires an integrated exploration and development strategy and a willingness to formulate a long term view. The implications this has for the continued momentum of development are discussed.
Poseidon: The Multiphase Boosting and Transportation Technology Now Reaching the Pre-Industrial Stage
Authors: Lafaille A. 
Published: December 2007

ABSTRACT
The POSEIDON Project, the first R&D Project entirely devoted to Subsea Multiphase Production, was launched in 1984, by TOTAL CFP, IFP and STATOIL. After nearly 7 years of joint endeavour, this international team work has resulted in the development of some completely new techniques and tools that are among the most promising today. This paper presents the overall strategy deployed by the POSEIDON partners from the beginning of the Project, and its evolution in the light of the demands of a changing subsea market.
Polymer Treatment for Water Control in High-Temperature Production Wells
Authors: Kohler N. , Zaitoun A. 
Published: December 2007

Abstract
A polymer treatment based on the use of a nonionic high-molecular-weight polysaccharide has been proposed for water control in high-temperature production wells. This polymer has excellent viscosifying power in all types of reservoir brines, high shear resistance and good thermal stability. Its ability to decrease the relative permeability to brine without affecting the relative permeability to hydrocarbons is demonstrated for both matricial sandstone and limestone reservoirs.
The superiority of this polysaccharide based water control treatment over other competitive processes seems obvious as soon as the reservoir temperature exceeds 70-75°C. With specially designed additives, treatments at temperature up to 120-130°C may be proposed. Moreover, because of its high shear resistance and its strong shear-thinning behavior this polysaccharide can be pumped at high injection rates with a slight wellhead pressure increase. Shut-in times of the wells treated may thus be considerably reduced.
The Effect of Temperature on the Gelation Time of Xanthan/Cr(III) Systems
Authors: Kolnes J. , Stavland A. , Thorsen S. 
Published: December 2007

Abstract
The potential for applying polymer gels for reducing the watercut in the North Sea reservoirs is increasing, as more reservoirs experience water breakthrough. In the high temperature environment near a North Sea producing well the effect of high and varying temperature can have large impact on the placement of the gel, which again is crucial for the performance of the process.
This paper reports a laboratory study concerning the effect of temperature on the rate of gelation of xanthan / chromium (III) systems. Measurements both in bulk and during flow have been performed. In the bulk experiments the gelation rate was determined using a low shear viscosimeter. The flow experiments were designed in such a way that the in-situ pressure gradient could be measured during the flow of gel in a Ballotini pack.
Bulk measurements showed that a linear relationship existed between the logarithm of gelation time and the reciprocal of absolute temperature. The slope of lines corresponding to different concentrations of xanthan and Chromium (III) were the same. Using the theory of Hurd and Letteron, the activation energy for the xanthan / chromium (III) reaction were calculated to 96 kJ/mol. Flow experiments were consistent with the results from the bulk-experiments, since the formation of flow resistance were seen to occur closer to the inlet as temperature increased.
A New Inhibitor for Scale Squeeze Applications
Authors: Pardue J. E. 
Published: December 2007

Abstract
Tests in Berea sandstone cores have been carried out which simulate scale inhibitor treatments by the precipitation squeeze method. The studies have shown that squeezes with common phosphonate inhibitors last twice as long as squeezes using common polymer inhibitors in cores containing brines with low calcium content (1,000 ppm). However, an inhibitor new to the oilfield has been shown to have a squeeze life double that seen with phosphonate inhibitors.
This new inhibitor is a phosphorous containing oligomeric product. As such, its residual can be determined easily in the field. This product is as effective as phosphonate inhibitors in controlling calcium carbonate and sulfate scales. It is superior to most products in controlling barium sulfate scales. This product should have special utility in reservoirs containing low concentrations of calcium.
How Ferrous Carbonate Kinetics Impacts Oilfield Corrosion
Authors: Tomson M. B. , Johnson M. L. 
Published: December 2007

Abstract
Operators have long observed that the severity of downhole CO2 corrosion is often largely dependent on location in the tubing string. At greater depths (corresponding to temperatures greater than 150 C), ferrous carbonate (FeCO3 or siderite) forms a tight adherent scale, effectively inhibiting corrosion. At intermediate depths, a patchy scale forms which results in accelerated pitting attack. A laboratory apparatus developed to test the temperature dependence of the kinetics and solubility of FeCO3 is described. Field and laboratory observations concerning ferrous carbonate scale adherence are compared to laboratory kinetics data. The solubilities and rates of formation of ferrous carbonate and calcium carbonate scales are contrasted.
Factors Influencing the Reaction Rate of Hydrochloric Acid and Carbonate Rock
Authors: Mumallah N. A. 
Published: December 2007

ABSTRACT
A systematic investigation of some factors which affect the reactivity of HCI towards carbonate rock was undertaken to provide technical criteria for the design and implementation of acid fracturing operations. This paper reports on the influences of pressure, temperature, acid concentration, flow rate, and gravity on the reaction rate of hydrochloric acid with carbonate rock. The experiments were conducted using an annular flow reactor which proved to be superior to previously reported reaction rate measuring equipment as it can be operated easily over a wide range of experimental conditions. The present study revealed that the reaction rate is an increasing function of temperature up to 200°F, then becomes independent of temperature above that. It is also an increasing function of acid concentration up to 15% but it becomes a decreasing function if the acid concentration is larger than 15%. The reaction rate is a decreasing function of pressure even if the pressure is larger than 1000 psi. The reaction rate is fastest when the acid flows in the direction of the gravitational force. To provide realistic data, laboratory determinations of reaction rates at high temperatures should be conducted under system pressures of 3000 psi or more.
Applications of the Electromagnetic Propagation Tool During Exploration of Block 16, Oriente Basin, Ecuador
Authors: Jones Russel N. S. , Belforte Alberto S. 
Published: December 2007

ABSTRACT
In reservoirs with low or varying salinity formation waters traditional methods of identifying and quantifying hydrocarbon saturation with resistivity measurements can be very difficult and inaccurate. The Electromagnetic Propagation Tool (EPT*) responds to the dielectric constant of the formation which leads to an alternative method for differentiating between water and hydrocarbon zones which does not depend upon salinity. For the recent eight well exploration program in Block 16 of the Oriente basin in Ecuador, the conditions were expected and found to be those where the EPT would help greatly with formation evaluation for wellsite decisions and also for analysis of residual hydrocarbons. In this paper a brief description is given first of the principle of measurement, tool design, interpretation methods and general applications of the EPT. A discussion of the geological background to the exploration program then follows, and finally the results obtained in two representative wells are presented and explained in detail.
High Pressure Swivel for Floating Production Systems
Authors: Pollack Jack , Carneiro Paulo R. B. 
Published: December 2007

ABSTRACT
The application of Floating Production Systems (FPS) has been limited to pressures of less than 3000 psi, because of the lack of sealing technology making large diameter high pressure toroidal swivels possible.
A joint industry project involving British Petroleum (BP), Mobil North Sea Limited, Petrobras, Petro-Canada, Statoil, and Sun Oil, was set up in 1987 to extend these pressure ratings to as much as 6000 psi.
A full scale prototype swivel, having an 8-inch nominal pipe diameter and a 48-inch toroid diameter, was fabricated and tested. The swivel sealing system was designed to seal 620 Bar static and 114 Bar dynamic applications. The testing of the swivel was carried out at the BP research facility using methane gas at 380 Bars and 93°C. The swivel sealing system included a pressure balanced isolation system, which protects the pressure seals from product ingress which can lead to seal deterioration. The swivel cycling simulated a 5 year operation of an articulated yoke type mooring system moored in North Sea conditions. At the conclusion of testing a rapid decompression of the swivel was performed.
Details of the swivel development, analysis, design, fabrication and testing is presented.
Marlim Field Development: A Challenge in Deepwaters
Authors: Vieira de Macedo Roberto Alfradique , Asrilhant Boris 
Published: December 2007

ABSTRACT
The Marlim Complex is a system of oil accumulations in the Campos Basin, offshore Brazil, which extends over an area of 381 sq km (94,100 acres), at water depths ranging from 400 m to 1,800 m (1,312 to 5,906 ft). With an estimated oil-in-place totaling 2.2 billion cubic meters (14 billion barrels), the Marlim Complex corresponds to 32 % of the Brazilian oil-in-place.
The overall development of the Marlim field itself will consist of several production systems, which will produce up to 109 subsea completed wells. The exploitation development plan will be divided into three step-by-step modules, in order to greatly reduce initial investments and allow development of technological capabilities in deepwaters.
Due to several delays in the beginning of the first module, called Pilot Production System, a one-year-test with start-up in the first quarter of 1991 will be used to gather performance data from a two-satellite-well production system. An additional eight-satellite-well production system will follow, complementing the original Pilot Production System, gathering reservoir and operational data during approximately a four-year period. All information will subsidize the overall field development.
The subsequent module, called Phase I, will consist of two semi-submersible units moored at 910 m and 980 m (2,986 and 3,215 ft) water depths and will start operating in 1994, with an estimated peak production of 31,600 cu.m/d (200,000 bpd) in 1996, from 32 wells. Phase II will correspond to the remaining part of the field development.
This paper describes many alternatives of drainage grids, production philosophy, subsea arrangements, and exporting of oil and gas shorewards for the Marlim field development plan. Additionally, an economical evaluation will demonstrate the profitability of the above mentioned Phase I cost-effective project.
Computer Control and Monitoring of Offshore Production
Authors: Pierce Dewey W. , Finch Clyde L. 
Published: December 2007

Abstract
This paper presents a new concept for supervisory control and monitoring of offshore gas-condensate production. The philosophy of the automation system's design, its attractive features, and operating experience gained to date are covered.

Introduction
The Lake Charles District of the CAGC Marine Region is predominantly a gas producing district operated by Continental Oil Co. for itself, producing district operated by Continental Oil Co. for itself, Atlantic-Richfield, Getty Oil Co., and Cities Service Oil Co. Gas discoveries and subsequent development in the East Cameron and West Cameron areas offshore from Cameron, Louisiana, now constitute a gas system consisting of 91 gas and gas-condensate wells located on 15 producing platforms. The gas system was put on production in 1958 after the platforms. The gas system was put on production in 1958 after the completion of a gas transmission line to the offshore platforms. Daily gas deliveries are averaging 350 MMcf along with 4,000 barrels of condensate per day. per day. The system has always been operated by personnel quartered in the field adjacent to one of the producing platforms. These operating personnel make daily trips by boat to their assigned platforms to check operations, change meter charts, pump inhibitor into the wells, and perform general maintenance duties. When personnel worked on a production platform, there was no communication with, or control of the producing variables.
Process Description Process Description The producing equipment on each of the platforms in the Cameron Gas System is basically the same, differing only in capacity and brand. The attached isometric drawing of a typical platform layout, Exhibit I, shows the components of the producing equipment, their relative positions on the platform and the flow plan of the connecting piping. platform and the flow plan of the connecting piping. In general the functions that are performed on the platform are separation of water and condensate from the gas, dehydration of the gas by glycol absorption, and disposal of the free water. In addition to the production separator through which the commingled production from all of the wells flows, there is a test separator for determination of each individual well's flow rate and liquid production at least once each month.
The well streams flow through individual flowlines into headers which are manifolded to facilitate flow either to the production separator or the test separator. The gas from the headers is expanded through adjustable chokes on the low temperature type separators, and separation of the free water and condensate is made. If it is necessary, the gas can be directed through a heating coil in the glycol reboiler to prevent freezing of the separator choke.
Maximizing Gas Recovery from Strong Water Drive Reservoirs
Authors: Randolph P. L. , Hayden C. G. , Anhaiser J. L. 
Published: December 2007

Abstract
Commercially viable production of 150 SCF/STB (27 m3/m3) of gas per barrel of brine has been achieved for reservoir pressure substantially below hydrostatic. Reservoir pressure at 9100 feet (2 990 m) has been drawn down to below 3460 psi (23 620 kPa) or 0.380 psi per foot (0.085 1 kPa/cm). Those wells having a gas/brine ratio in excess of 100 SCF/STB (18 m3/m3) flow because of lift by produced gas. Injection of lift gas is used 1) to start production after wells are shut-in, 2) to maintain production for lower gas/brine ratios, and 3) to increase rate or to increase wellhead pressure for operation of the surface facilities.
Key features of the well completions and surface facilities to maximize recovery are: Minimizing friction losses by 1) using annular production, 2) installing tubing only to the depth required for gas lift and chemical injection, 3) using large-diameter wellhead valves and downstream piping, and 4) injecting scale inhibitor through chemical treat strings.Utilizing freewater knockouts followed by separate oil-gas separators that facilitate cooling of condensate before placing it into the stock tanks. This minimizes evaporative loss.Keeping operating costs low by 1) maintaining brine pressure above atmospheric to keep oxygen out of the system and to reduce disposal pumping costs, 2) creating large sand surface areas in the disposal zones to reduce the injection pressure, and 3) using the same compressor for both gas lift and gas sales.
Use of Surface Seismic Data to Predict Formation Pore Pressure Worldwide
Authors: Weakley R. R. 
Published: December 2007

ABSTRACT
An accurate prediction of formation pore pressures prior to drilling a well can significantly improve drilling performance, reduce the number of costly drilling problems encountered, and in many instances, can be the determining factor in successfully reaching objectives. This is particularly true when dealing with exploratory wells. The fact that we are going to penetrate the same stratigraphies as offset wells does not equate to being in the same pore pressure environment. In fact, when dealing with exploratory wells, there is a high percentage of the time when this is not the case.
This approach to predicting formation pore pressures utilizes offset log information, and velocity information from surface seismic data. All surface seismic data has velocity information built into it in the way of stacking velocities. From these stacking velocities, estimates of interval velocities can be made. We have developed a quantitative technique for determining formation pore pressures from the relative changes in these velocities.
From the stacking velocity data, we develop curves we refer to as ITT (Interval Transit Time) curves. ITT curves are generated at offset locations as well as the proposed drilling location. Actual offset well pore pressures are determined from the logs and the ITT curves at these offsets are calibrated to the known pressures. After this calibration process, the ITT at the proposed location can be interpreted to predict formation pore pressures to be encountered.
The combination of these tools yields a reliable pore pressure scenario from which to plan a drilling program and execute the operations. This procedure has been utilized on numerous wells throughout the Gulf of Mexico as well as a number of wells around the world. The technique will be illustrated with figures as a step by step analysis is done. Results of the use of this methodology will also be illustrated.
An Evaluation of Carbon Dioxide Flooding
Authors: Mungan Necmettin 
Published: December 2007

Abstract
Laboratory core displacement tests were made to better understand the effects of miscibility, swelling and viscosity reduction on oil recovery by CO2 flooding. Also, certain field applications were reviewed to assess performance of CO2 flooding under miscible and immiscible conditions. Achieving miscibility is shown not to be essential to recovering incremental oil since viscosity reduction and oil swelling can also be very important. Recommendations are offered as to how best to pilot test CO2 flooding in the field to obtain reliable performance data.
Minimizing Drilling Fluid Waste Discharges While Drilling an Arctic Exploratory Well
Authors: McKay M. , Seward M. W. , Smith G. , Brady S. J. 
Published: December 2007

ABSTRACT
Ever more restrictive regulations have necessitated minimal impact drilling procedures that have led to the development of a variety of methods for the disposal of liquid drilling waste. Current Alaska regulations severely limit the use of reserve pits other than in an emergency situation for the disposal of liquid phase waste. Current efforts are being directed at minimizing liquid discharges while conserving water and maximizing solids control efficiency.
This paper presents a case history of a recent project on Alaska's North Slope where operator requirements and logistics necessitated on site dewatering of drilling fluids. A retrofitted chemically enhanced centrifuge was utilized for this process. The design, fabrication, operations, and economics are summarized. The conclusions should prove beneficial for future planning of restricted discharge drilling operations such as will be necessary should Alaska's Arctic National Wildlife Refuge be opened to drilling.