bluuebunny/crossref_metadata_2025_split huggingface dataset:
Implications of Brine Mixing in the Reservoir for Scale Management in the Alba Field
Authors: Paulo J. , Mackay E. J. , Menzies N. , Poynton N. 
Published: December 2007

Abstract
This paper brings the discussion on brine mixing initiated at the 1999 SPE Symposium on Oilfield Scale full circle, and suggests that different scaling regimes may exist in any given reservoir that should impact the scale management strategy. The initial paper by White et al. (1999) identified lower than expected barium levels in many wells in the Alba field, and raised the question of where scale deposition is occurring. A follow-up paper at the same meeting the following year by Mackay and Sorbie (2000) identified from a theoretical standpoint where brine mixing should be expected, and suggested that significant scale deposition may occur deep within the reservoir, particularly where a large proportion of injected water sweeps through the aquifer. The current paper seeks to apply that theoretical analysis to the Alba field, on a well-by-well basis, to establish whether diagnostic tests can identify which wells should be treated conventionally, and which require special attention.
Firstly, production data and produced brine compositions are analysed to identify any recurring patterns. Wells are then classified and grouped according to various types based on this analysis. Well properties such as location within the reservoir and orientation to the flood front are then compared to identify whether they can be used to give a similar grouping of wells. Three principal zones are identified, with position relative to the injection wells and the aquifer identified as key parameters. Secondly, the flow patterns around each well are studied using the existing reservoir flow model. Modelling the dynamic mixing patterns throws further light on the differences between the zones, with scale dropout predicted in the aquifer in some areas, and in the oil-leg in others.
Recommendations are made regarding the treatment of existing wells and the optimum positioning, from a scale prevention perspective, of any new wells.
Lead Deposits in Dutch Natural Gas Systems
Authors: Hartog F. A. , Jonkers G. , Schmidt A. P. , Schuiling R. D. 
Published: December 2007

Abstract
During the production of natural gas from Dutch Rotliegend and Kupferschiefer sediments, next to "conventional" carbonate and sulphate scales, sometimes also lead deposits are formed. These deposits, which vary in composition from galena (lead sulphide) to elemental - metallic - lead and complex lead(hydr)oxides, may form a serious thread to operations because of their tendency to cause the blocking of production equipment or (water) injection pumps and tubing. In some cases radioactive lead (lead-210; half life 22.3 years) is incorporated into these compounds at levels above regulatory concern, which necessitates additional safety measures during operations and maintenance.
In sour gas wells, the deposition of galena can be explained by local supersaturation (caused by a sudden temperature or pressure drop) where bisulphide anions react with lead cations in the produced water, in which concentrations of up to 150 mg lead per litre brine have been detected. In the absence of hydrogen sulphide and even in "dry" gas wells, the deposition of metallic lead has been observed locally at rates of 10 grams per day or more. An electrochemical mechanism is held responsible for lead deposition on carbon steel tubing: iron from the tube wall is oxidised by lead ions in solution, leading to corrosion of the wall and the deposition of lead scales with a thickness of 10 mm or more. Under unfavourable conditions or during maintenance operations, metallic lead is easily converted into secondary lead minerals.
Detailed knowledge on the (geological) origin, the transport pathways to surface facilities and the mechanisms of lead scale formation, might enable the future development of techniques by which lead deposition can be prevented.
An Electrochemical Approach For The Protection Of Metal Surfaces From Formation Of Calcium Carbonate Using Bulk "Jar Tests"
Authors: Labille S.C. , Morizot A.P. , Neville A. , Graham G.M. 
Published: December 2007

Abstract
This work describes the beneficial effects of an electrochemical treatment on scale adhesion and formation. Previous studies by the present authors have shown that an electrochemical treatment can be used to promote the adsorption of polyelectrolyte inhibitors at metallic surfaces. The objective of this project is to observe the effects of the inhibitor film, deposited electrochemically, on the scale formation. "Jar tests" have been carried out. Four techniques, namely SEM, AFM, optical microscopy and scale dissolution, have been used to quantify the deposition in the presence and absence of the inhibitor film. The electrochemical treatment in presence of Mg has shown some promising results to inhibit calcium carbonate scale. The mechanisms relating to the formation of the Mg/inhibitor-containing film adsorbed during the electrochemical treatment and the potential applications of the technique will be discussed.
Laboratory Determination of Calcium Carbonate Scaling Rates for Oilfield Wellbore Environments
Authors: Zhang Yuping , Farquhar Rod 
Published: December 2007

Abstract
Calcium carbonate is a commonly occurring oilfield scale which proves to be difficult to manage. Carbonate scale prediction can be improved by considering the kinetic chemistry in addition to the conventional thermodynamics based predictive techniques. To improve the performance of a predictive model, a thorough understanding of the physical influences on carbonate scale kinetics is required. The work presented in this paper includes new data, experiment technique improvements and preliminary investigations into the efficiency of scale inhibitors. The new data acquired from the experiments described in the paper has been incorporated into our existing kinetic scale prediction model and a combined thermodynamic and kinetic computer model has been developed. An example is given which demonstrates how the combined model can be used to predict oilfield downhole carbonate scale profile and study the impact of production parameter changes, such as increasing water cut.
An Experimental Study to Evaluate Water Vaporisation and Formation Damage Caused by Dry Gas Flow through Porous Media
Authors: Zuluaga E. , Muñoz N. I. , Obando G. A. 
Published: December 2007

Abstract
Experiments were conducted to evaluate the rate of water vaporisation and the consequent permeability reduction caused by the flow of dry gas through porous media. Two sets of porous media were studied: unconsolidated Ottawa sandpacks and consolidated Berea cores, as well as various salinity brines ranging from 0 to 150 g/litre of NaCl. The experiments were conducted at an initial water saturation of about 14% for sandpacks and 24.6% for Berea cores. Tests indicate that the rate of water vaporisation increases with gas flow rate and decreases with salinity. The vaporisation of water from the porous media can result in halite drop-out. This might cause a reduction in the permeability of the porous media. The experiments showed that the reduction in permeability for sandpacks ranged from 0% for the lowest salinity to around 21% for the highest salinity used. In consolidated Berea cores this reduction ranged from 9% to 53% for the lowest and highest salinity respectively.
High Density CCL Memory Tool To Confirm SSD Sleeve Position
Authors: Daniels Jim , Williams Garry 
Published: December 2007

Abstract
A large number of Mœrsk Olie Og Gas AS completions in the Danish Sector of the North Sea utilise Sliding Side Doors (SSD's) as a means of zonal isolation. As the majority of the completions are in highly deviated / horizontal wells, these sleeves are manipulated by shifting tools on coiled tubing (CT). Experience has shown that the operating of SSD's on coiled tubing can lead to uncertainties in the true status of the sleeve position. Several cases have arisen where subsequent Memory Production Logging Tool (MPLT) surveys have identified SSD's that were not in their expected status.
Though MPLT's were successful in the determination of SSD status, operational and cost considerations required a new approach. What was required was a reliable, accurate means of verifying SSD sleeve position with data acquired on the same run as the sleeve manipulation tool. There were two strands to this project, the proof of concept in the ability to identify sleeve position using Memory Casing Collar Locator (MCCL) data, and the development of a "stand-alone" MCCL tool, rugged enough to be run in conjunction with the SSD manipulation tools.
A novel approach for tubing repair in a HPHT well
Authors: Rodenboog Coen , Staal B. J. 
Published: December 2007

Abstract
This paper describes the various steps involved to safely suspend a HPHT well and to repair a number of leaks in the production tubing. The tubing leaks were the result of corrosion and occurred over a two hundred meter interval.
Thorough analysis and associated difficulties to resolve this problem lead to the approach of cementing the tubing in place. Thus allowing the operator to test this gas well and increase the knowledge of the reservoir to develop this field. The process and solution will be described in great detail and will serve as the basis for similar problems in the future.
Development of Collapse Ratings for High Temperature and Pressure Coiled Tubing Applications
Authors: Luft H. B. , Wright R. , Lallemant F. , Kis P. 
Published: December 2007

Abstract
In the spring of 1998, BJ Sevices and Total Oil Marine carried out an "HP Intervention Feasibility Study" for the reliable entry of a high pressure gas well using 1 ¾" 100 ksi Coiled Tubing. The research was prompted by the requirement to use Coiled Tubing to enter Triassic wells on the Alwyn North platform in the North Sea for post frac cleanout operations among other service requirements. Potential wellhead pressures of 7,500 psi and operating depths of 6,000 metres meant that a better understanding of Coiled Tubing collapse mechanisms and an improved method of predicting collapse would be vital to optimize operations on Triassic wells. The first phase of this study was based on experimental fitness-for-purpose investigations involving a 3060 ft long test string at an on-shore test well in Aberdeen, Scotland. Recognising the conservatism of collapse resistance predicted by existing theoretical methods and appreciating that knowledge of actual collapse limits is more critical in High Temperature and High Pressure (HPHT) coiled tubing operations, this initiative culminated in a joint research venture between the operator and the coiled tubing service provider. The second phase of this research involved a laboratory collapse-testing program conducted in Edmonton, Alberta, that set out to obtain extensive experimental data on CT collapse and to investigate the effect of loading history on the residual collapse strength.
This paper is concerned primarily with the laboratory-testing program. The testing protocol is described and the key parameters that influence collapse resistance are identified and discussed, as well as how each may be affected by plastic cycling, high temperature and/or high pressure operations. Some selected experimental results are presented. Although actual factors of safety against collapse requires knowledge of the individual test results, general trends for the degradation of collapse resistance due to prior service loading and the range in magnitude of the difference between actual and predicted collapse strength, are identified. Theoretical predictions of collapse resistance are based on existing formulations in which the ovality and axial loading appear as explicit parameters. Collapse predictions are also discussed in light of a newly proposed methodology submitted to the API under RP 5C7 as recommended practise for determining allowable collapse pressures on coiled tubing. A new methodology for accurate prediction of CT collapse that is based on measured stress-strain plots, is also discussed.
To Straddle or Not to Straddle -- The Inflatable Option
Authors: Mackenzie Gordon R. J. 
Published: December 2007

Abstract
This paper examines the use of coiled tubing deployed thru-tubing inflatable packers in a straddle configuration. Many times this straddle option can be used to prolong the life of a well without the time-consuming and resource-sapping operation of having to perform a complete well workover. Couple the resulting economics with the operational advantages of not having to kill the well and a completion in situ inflatable straddle option may and has offered operators in the global oil and gas industry a very real and viable option.
During the course of this paper the inflatable straddle option is examined and discussed as is the operational deployment and options of such a system. Running a single trip straddle and running a multiple trip down hole assembled system are highlighted. Four case histories will be disseminated to provide a balanced opinion on the effectiveness of such a system. The four case histories include a chrome system to match the already installed completion metallurgy and the highlighted wells will vary in geometry up to that of a horizontal gas well.
The paper goes on to discuss the longevity of such a system with at the time of submitting this abstract one of the featured systems having been in position in a producing environment for in excess of five years.
Using Mature Selective Re-Entry Technology to Manage Risk at Wytch Farm: A Case History
Authors: Brunnert David J. 
Published: December 2007

Abstract
This paper describes how the team at Wytch Farm met the challenge of drilling and completing selective re-entry laterals in an increasingly price competitive and performance-focused environment. One of the key elements in this success was the creative application and modification of existing technology. Utilizing predominantly mature technology, the team was able to proceed with confidence in the management of risk associated with new applications.
SPE/WPC/AAPG Resource Definitions as a Basis for Portfolio Management
Authors: Ross J G 
Published: December 2007

Abstract
In February 2000, three major international organizations, the SPE, WPC and AAPG jointly approved and published a significant document entitled Petroleum Resources Classification and Definitions1. This achievement represented a major step forward in the industry's attempts to improve the level of consistency in the documentation and description of resources that do not satisfy the criteria for reserves. The existing (1997) SPE/WPC reserves definitions2 were unaffected; the new definitions simply supplemented the 1997 definitions in order to cover the entire resource base. In addition to providing a single set of terminology for industry use, the document also provided a new classification system that was designed to facilitate the development of portfolio management systems by individual countries or companies.
The potential benefits of the SPE/WPC/AAPG classification system are twofold. Firstly, it provides the facility to expand the sub-division of project maturity, in order to classify projects on the basis of the work required (reflecting business decisions and budgeting) to move them towards commercial production and revenue. This ensures a continuous focus on the objectives of asset management, as well as providing the potential for a detailed classification of the resource base which illustrates clearly the balance of the portfolio and hence facilitates rational decisions on future acquisitions/divestitures.
The second benefit of the new system lies in the consistent approach to establishing a range of uncertainty, regardless of project maturity, which allows the very powerful tool of uncertainty tracking to be applied. Despite being first published by Arps3as long ago as 1956, this method is surprisingly little used. In practice, it is the only way to track estimates of recoverable volumes in a meaningful way, and to establish on an on-going basis the validity of the methods used to estimate those volumes.
Using Portfolio Analysis to Develop Corporate Strategy
Authors: Howell John I. , Tyler Peter A. 
Published: December 2007

Abstract
Every exploration and production company has the difficult task of deciding between a large number of competing oil and gas projects for future investments. Many companies are developing corporate strategies and making investment decisions without considering the relationship between the two. The result is a less than optimal financial performance and failure to meet corporate goals. The application of portfolio analysis within the strategy and investment stages provides a disciplined and systematic method of analyzing these relationships. Portfolio analysis can be used to develop and compare strategies given a "pool" of investments. Conversely, portfolio analysis can also be used to evaluate individual investments with respect to how they impact the company's ability to meet its strategy. Effective portfolio analysis requires high-quality data addressing such questions as: what assets are currently owned, which ones might be purchased, what stakes might be acquired, or what stakes might be developed in the near future? By taking on a particular economic project, is another opportunity missed that has a better net return? This presentation will illustrate the use of portfolio analysis to develop and compare alternate strategies that a company might pursue. The examples illustrate how projects and corporate performance measures interact and how the interactions create new opportunities for the corporation. The interactions can be quantified in terms of simple graphical summaries that allow decision-makers to compare alternate strategies and quickly assess the business performance trade-offs they will likely face when they select one strategy over another.
E&P Asset Value and Its Implications on Share Price
Authors: Jacobson Gregg A. 
Published: December 2007

Abstract
Every day E&P companies are confronted with opportunities and decisions, which will impact the value of the assets and enterprise that they manage. As the goal of publicly held companies is to maximize shareholder value, companies tend to respond by attempting to maximize Wall Street's preferred valuation metric of the day. Return on capital employed (ROCE), cash flow per share, reserve replacement and finding and development costs per BOE are used to judge the industry's performance over time; but the most significant determinant of both absolute and relative shareholder returns remains a company's ability to increase the value of its reserve base in an economic fashion. A multi-year study of 45 publicly held independent E&P companies establishes the strong correlation between reserve value and share price performance.
The Hydrocarbon Asset Valuation Solution: Making Major Investment Decisions 50X Faster, With Improved Accuracy
Authors: Ghazi T. Y. , El Rafie E. A. 
Published: December 2007

Abstract
Despite recent improvements, major investment decisions are often taken before the technical and business analyses are complete. Even when they are complete, managers are repeatedly left confused by mixed messages from the many disciplines involved. The result is avoidable costs and missed opportunities totaling hundreds of millions of dollars annually.
To solve this problem, we have re-examined all aspects of existing decision-making methods and have created a new way to facilitate crucial decisions much more quickly and clearly. This paper describes this new Hydrocarbon Asset Valuation (HAV) solution, and shows examples of how HAV can reduce cycle times by as much as 50X with improved accuracy and covering a wider range of uncertainties.
HAV consists of five elements: the team, the process, the tools, the room, and the data. The team includes all of the technical and business disciplines that impact the investment decision. The process enables a team to intensively collaborate for two to three weeks in one room to meet a common objective. They work in parallel, and produce several shared earth models, multiple reservoir simulations, numerous surface facility options, and dozens of marketing and business scenarios. This input ultimately converges on a critical few alternative development scenarios. The tools consist of simple yet powerful PC-based products for geoscience interpretation, reservoir simulation, surface facility configuration, economic scenario analysis and electronic documentation. This new software platform is far less expensive than conventional workstation-based products, and is much easier to use. The room is a large well-equipped room where the team meets and works through the process without interruption. Finally, the data includes a carefully extracted subset of the technical and business data to help characterize only those factors that impact profitability.
In one recent HAV example, a 35-person team fully articulated the value of an offshore block containing 51 assets in all phases of the life cycle in just two and a half weeks. This amounted to a 50X reduction in cycle time, with the improved accuracy that comes from synergy in all of the disciplines from seismic interpretation to marketing.
A Comparative Analysis of 12 Economic Software Programs
Authors: Wright John D. , Thompson Robert S. 
Published: December 2007

Abstract
One would expect that different economic programs should compute the same answers given the same problem statement. This hypothesis was tested by providing a very simple problem to a number of industry personnel using various software programs. The results show a significant and surprising difference in calculated values between the various programs. In 2000, a large project conducted by the Society of Petroleum Evaluation Engineers found that the differences arise from a combination of unstated assumptions; differences in interpretation of various parameters; different, but equally valid, treatment of factors such as discounting or escalation; and apparent misunderstanding of the problem statements. The results of the study indicate that there is a great need for standardization and communication regarding upstream economic calculation.
Integrated Optimization on Long Horizontal Well Length
Authors: Cho Hyun 
Published: December 2007

ABSTRACT
Though the drainage area of horizontal reservoirs is increased with increase in horizontal well length, construction costs for drilling and completion also increase; this combines with other factors to negatively affect the overall economics of the horizontal well. However, no reliable standards are currently available that take into account the factors necessary for the determination of optimum well length for horizontal drilling.
This paper presents a methodology developed to obtain the optimum horizontal well length based on total economics as well as productivity index (PI) change associated with frictional loss effects in the long section of the horizontal wellbore. An integrated approach is proposed for quantitative analysis of the parameters affecting productivity and economics in order to achieve the overall optimum performance of a horizontal well project. This study shows that production is no longer proportional to the horizontal well length after a critical point. The critical point is calculated as a function of the length of the horizontal production section, flow rate, drawdown pressure, and other parameters. A step by step calculation procedure with examples is described with sets of graphical charts developed for illustrating the relationships between the various parameters. The results can be used directly to determine the optimum horizontal well length in multiple well projects.