bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Design and Deployment of Enhanced Scale Dissolver/Squeeze Treatment in Subsea Horizontal Production Wells, North Sea Basin
Authors: Jordan M. M. , Hiscox I. , Dalton J. F. , Mackie J. , Kemp S. 
Published: December 2007

Abstract
This paper presents an overview of life cycle flow assurance management for a subsea development by focusing on scale control. To illustrate this approach field results from 6 dissolver/squeeze treatments using novel solvent packages to enhance the performance of both carbonate/sulphate scale dissolvers are cited. Subsea horizontal production wells were stimulated and protected using this treatment method. The dissolver and squeeze treatments applied to the horizontal wells utilised a thermally degrading wax divertor to temporarily impair injectivity in the heel region thus allowing propagation of chemical along the wellbore.
The paper will outline the principles by which dissolvers function and the increase in dissolver efficiency made possible with the use of a surfactant package. The practical concerns about deployment methods within subsea production wells are also emphasised.
The deployment technology developed for these treatments was adopted to allow the dissolver surfactant packages to be placed into the near wellbore region so stimulating production prior to application of future squeeze treatments. This paper clearly shows that it is possible to improve dissolver effectiveness by the use of surfactant packages while having minimum impact on treatment cost. The deployment of the dissolver chemicals in all cases stimulated production in the wells, which resulted in the cost of the treatment being recovered between 2 and 23 days. The deployment methods used for these treatments into sub-sea horizontal wells reduced the need for expensive coiled tubing intervention so improving the economics of this method of scale management in a maturing oilfield
Comparative Study of Different Barite Dissolvers: Technical and Economic Aspects
Authors: Lakatos I. , Lakatos-Szabó J. , Kosztin B. 
Published: December 2007

Abstract
An extensive research programme was launched with the aim at evaluating the potential of seven different polyamino carboxylic acids (PACAs) using both technical and economic aspects. Dissolving capacity of each compounds was determined under equilibrium conditions as a function of concentration for barite and reservoir rock (sandstone). The absolute and relative selectivity of dissolution, viz. the matrix effect of formation rock were precisely analyzed. Dissolution of barium sulfate, calcium and magnesium carbonate and iron compounds was followed in time, and thus, the kinetic calculation could also be made.
Results of the research programme provided reliable data for comparison of dissolution capacities under identical chemical (equilibrium, kinetic, dissociation, etc.) conditions. On the basis of the experimental findings it was concluded that the sequence of dissolution capacity is different if the results were evaluated in technical or economic senses. It was also shown that the preferentially used compounds (e.g. DTPA, and particularly EDTA) are not the best choices when technical considerations are only enforced. The economic grounds, however, may partly justify their application at the expense of poor efficiency. The systematic analysis of the mentioned dissolvers may open new vistas in mitigation of formation damage caused by barite or barium sulfate scales and accelerate the search for more effective mixtures of complex-forming agents to be applied under field conditions.
Pushing the Envelope: Successful Hydraulic Fracturing for Sand Control Strategy in High Gas Rate Screenless Completions in the Jauf Reservoir, Saudi Arabia
Authors: Solares J. Ricardo , Bartko Kirk M. , Habbtar Ali H. 
Published: December 2007

Abstract
Hydraulic Fracturing for sand control techniques in screenless completions have been successfully attempted, predominantly in oil wells, by operators the world over; whereas, frac-packing has rapidly become the preferred option for high rate gas wells in highly permeable reservoirs.
Saudi Aramco is currently undertaking one of the largest gas development projects in the world comprising a large number of new deep wells, four world-class gas plants, and massive development of new infrastructure.
The Jauf reservoir, one of several forming part of the gas development project, is a sandstone with unique characteristics, because it exhibits low to moderate permeability but high sanding tendency caused by high degree of rock unconsolidation under high pressure and temperature conditions. Frac-packing was considered as a potential sand control technique early during the planning phase, but the relatively low permeability encountered upon testing of the first Jauf reservoir producers clearly indicated that highly conductive, long half-length hydraulic fractures would be required to meet gas rate project targets. Hence, the decision to pursue fracturing for sand control techniques with screenless completions techniques was made.
This paper presents the results of a performance driven process, successfully implemented by Saudi Aramco in partnership with Schlumberger, which has achieved sand and solids free gas production in a score of wells treated to date. A detailed description of the combination of effective techniques applied as part of the process is provided, and lessons learned throughout the fracturing campaign are shared. The solids free gas production rates achieved in the wells discussed herein range from 10 to 50 MMSCF/D at high condensate yields. All wells were repeatedly cycled and, in some cases, limitation on the testing equipment used prevented testing wells at higher solids free rates to achieve full potential.
Development of the Alba Field – Evolution of Completion Practices, Part 2 Open Hole Completions; Successful Outcome – Drilling with SBM and Gravel Packing with Water Based Carrier Fluid
Authors: Murray G. , Morton K. , Blattel S. , Davidson E. , MacMillan N. , Roberts J. 
Published: December 2007

Abstract
Chevron has been successfully drilling and gravel packing open hole horizontal wells on the Alba Field (central North Sea) since 1998 and 13 open-hole gravel packed (OHGP) wells drilled with water based mud(WBM) are currently in production with no history of sand production. Although these wells have been hugely successful with significant net present value (NPV) returns it was recognised that the future, mature redrill and infill targets cannot sustain the current costs associated with traditional OHGP completions. The challenge was to develop alternative techniques to maintain the benefits of OHGP wells but to achieve a low cost well and completion concept to assist in realising new drilling opportunities.
To drill the shale above the top of the reservoir and the productive interval in a single hole section would remove the conventional requirements to set an additional casing string and change over to a water based system prior to drilling into the reservoir. This would save costs but raise a question over the gravel packing operation. Hitherto, attempts to gravel pack involving á/â placement techniques using an aqueous carrier fluid following drilling with oil based systems have had only limited success.
The prospective problems were examined by extensive laboratory tests carried out by Baroid and Chevron in co-operation. A new synthetic oil based mud (SBM) formulation was developed and compatible displacement fluids and procedures were devised.
Based on this work, 1500 ft of shale and reservoir were drilled; a liner was installed – predrilled over the reservoir section - and screen was run inside the liner. Gravel was pumped using brine as carrier fluid and complete gravel placement was achieved. The well has achieved productivity levels at least as good as existing WBM wells. A second well completed in the same manner has given similar performance.
This combination of a liner system and SBM fluids offers several advantages. There is the prospect of considerable savings with respect to operating time, cementing and drilling fluids. Also the liner gives protection to the screen.
This new approach which represents potential large savings in costs and excellent productivity is considered to be very applicable for expandable sand screens (ESS), multi-lateral completions and additional redrill targets both on Alba and worldwide.
Balance Between Formation Damage and Wellbore Damage: What is the Controlling Factor in UBD Operations?
Authors: Guo Boyun 
Published: December 2007

Abstract
Underbalanced drilling (UBD) has been considered as an effective means of formation damage control during drilling. However, there is a trade-off between formation damage and wellbore damage in UBD. The wellbore damage includes borehole collapse, cave-in and washout associated with the lowered bottom hole pressure. The damaged wellbore results in the increased drilling cost and also brings in completion problems such as poor cement bonding quality and/or cement collar being too thick to be penetrated during perforating job.
While the highest bottom hole pressure during normal drilling condition affects the degree of formation damage, the lowest bottom hole pressure during pipe connection controls severity of the wellbore damage. Both the highest bottom hole pressure and the lowest bottom hole pressure are controlled by the combination of the liquid and gas flow rates. In order to minimize both the formation damage and wellbore damage problems, it is highly desirable to have an easy-to-use approach to generate balanced design of combinations of liquid and gas flow rates under given drilling conditions. The content of this paper fills the gap.
This paper presents an innovative procedure to approach the optimum design of liquid and gas flow rates combinations for UBD under given geological constraints. The optimum flow rate combinations are selected from a liquid-gas rate window. The liquid-gas rate window is an envelope in the liquid flow rate vs. gas flow rate plot. In developing the liquidgas rate window, formation fluid pressure limits the upper bound of the flowing bottom hole pressure and wellbore collapse pressure serves the lower bound of the circulation breaking bottom hole pressure. The window is closed by fluid's cutting carrying capacity and wellbore washout criteria.
This paper first time provides drilling engineers with an easy-to-understand procedure to optimize mud and gas flow rates in UBD.
Gravel Pack Designs of Highly-Deviated Wells with an Alternative Flow-Path Concept
Authors: Sanders M. W. , Klein H. H. , Nguyen P. D. , Lord D. L. 
Published: December 2007

Abstract
Alpha-Beta gravel packing procedures have been used with a moderate degree of success in highly-deviated wells. Incorrect concentrations of gravel and/or pump rates can result in bridge formation in the open hole/screen annulus and Beta wave initiation prior to reaching the toe. If there is a high leakoff zone, gravel concentration will increase, and there may be insufficient velocity to transport the solids farther down the well. Either factor or a combination of the two can lead to formation of a bridge in the openhole/screen annulus and an early initiation of the Beta wave. Other effects that could lead to bridge formation include: flow restriction and blockage from collapse of an unstable open hole section, and changes in annular velocity transition from one hole size to another. Incomplete gravel placement and the presence of voids around the screen can result from all of the complications described above. To overcome these, an alternative flow-path system has been developed. If a bridge forms, the alternative path allows the slurry to bypass it. A number of physical models have been used to design and examine the effectiveness of the system, which has been validated in field applications.
A numerical model has also been developed to assist with the gravel pack designs in highly-deviated wells. The model simulates the alternative flow-path concept as well as conventional gravel packing in open hole or cased-hole completions of arbitrary deviation. Details of the alternative flow-path scheme as well as the formulation of the numerical model are presented in this paper. Simulation results were compared to observations in the physical models.
The Optimization Of The Productivity Index And The Fracture Geometry Of A Stimulated Well With Fracture Face And Choke Skins
Authors: Romero Diego J. , Valko Peter P. , Economides Michael J. 
Published: December 2007

Abstract
The post-treatment performance of hydraulically fractured wells has been a recurring theme in the petroleum literature, covering the spectrum of understanding the physics of flow to the optimization of design. Optimization itself has taken different hues meaning comprehensive economic, or just the reduction of execution costs, or the maximization of the production or injection rates.
Irrespective of the ultimate criterion, the magnitude of the reservoir permeability has been central to the fracture morphology. Long fractures are warranted for low-permeability reservoirs; wide but short fractures are indicated for high-permeability formations. For a given reservoir of known permeability and dimensions the mass of proppant injected to the pay describes a unique and constant proppant number for which a maximum well productivity index can be achieved at the optimum dimensionless fracture conductivity. The proppant number and the optimum dimensionless fracture conductivity determine exclusively the optimum fracture dimensions.
However, damaged hydraulic fracture performance deviates substantially from that of undamaged fractures. Two types of damage are considered, fracture face, often caused by fluid leakoff into the reservoir and choke fracture, which is caused by proppant flow-back, over-displacement or polymer damage. These damages, described by skin effects cause a departure, at times substantial, from the indicated undamaged optimum fracture geometry.
In this work, the performance of a fractured well is calculated using a direct boundary element method. The method calculates the dimensionless productivity index and the model allows for the presence of the two different skin effects. The fracture face skin effect was found to have a significant detrimental effect on the dimensionless productivity index, especially for high-permeability reservoirs. The effect of the choke skin was found to be potentially also very detrimental, but less complex to account for, because it can be represented as an apparent reduction to the proppant number.
Last Chance Production Enhancement Opportunities for Near-Depleted Zones
Authors: Sobernheim D. W. , Page W. H. , Womack A. L. 
Published: December 2007

Summary
As part of an over-all reservoir management strategy, production enhancement techniques for near-depleted wells fit in to a pre-abandonment analysis step for determining if additional gas or oil can be economically recovered prior to well or field abandonment using some form of workover intervention.
It is widely recognized that over time, a near wellbore skin may develop in completions that were relatively undamaged originally. We present methodology for determining appropriate candidates for production enhancement in nearly depleted, declining, high-skin oil and gas wells. Our case studies include candidate recognition, job economics, and practical execution information related to performing stimulation workovers in low-pressure wells with significant skin. Wells with pressure gradients as low as 0.1 psi/ft have been successfully stimulated with these skin reduction techniques and returned to production. To work properly, the stimulation must use energized and/or foamed fluids, the chemistry of the treatment must be optimized for maximum stimulation and clean-up, and a reliable and rapid flowback procedure must be implemented.
The new technique relies upon pressure transient testing or advanced decline-curve analysis for the skin diagnosis, the current average reservoir pressure, and an analytic production prediction model combined with production system analysis to project the results of an intervention. This technical analysis ties into an economic one, which seeks to determine if an economically beneficial intervention is possible and to assign a risk profile to the project
Role of Starch in Designing Nondamaging Completion and Drilling Fluids
Authors: Simonides Hylke , Schuringa Gerhard , Ghalambor Ali 
Published: December 2007

Abstract
Starch is a polymer that is widely used in all types of water based drilling fluids. With the development of specialty drilling and completion technologies, starch is also chosen as one of the main components of drill-in fluids. This paper presents laboratory results obtained from experimental work on chemically modified potato starch. The results show, that properties like heat and shear resistance can be improved by chemical modification.
The main functions of starch are fluid loss reduction and rheology control. In drilling fluids the polymer interacts with solid particles to enhance the seal of the filtercake on the wellbore, and to provide the required rheology. Reasons for choosing starch are its versatility, and compared to many biopolymers, its relative low cost. During drilling operations the fluid rheology has to be controlled over a large temperature interval. Like many polymers, starches tend to degrade at high temperature. The degradation will lead to increased fluid loss and changes of the fluid viscosity, which can result in fluid failure and lead to formation damage. It is well known that one of the factors affecting the thermostability of a drilling fluid is the composition of the drilling fluid. Another factor is the nature and the chemical modification of the starch. The starch has been modified by cross-linking and carboxymethylation in order to improve the properties in drilling fluids at ambient and elevated temperature.
Fluid properties such as fluid loss and viscosity will be presented as a function of the level of cross-linking. The results indicate that high molecular weight starch exhibits the best fluid loss control combined with a shear thinning rheology, but there is an optimum for both when increase of the molecular weight is obtained by crosslinking. Crosslinking does positively affect the heat stability. The effects of substitution and cross-linking on the resistance to heat and pH are discussed for several fluid compositions. The fluids have been aged at elevated temperatures under dynamic conditions.
A new heating apparatus was developed to perform these tests. This apparatus consists of a bath equipped with a mechanical device to rotate fluid containers, like in the traditional hot air roller ovens. The bath is filled with silicon oil, which is circulated, rendering a homogeneous temperature profile. The dynamic aging results thus obtained have proven to be more reliable than those obtained with conventional hot air ovens. A detailed description of the new apparatus will also be presented.
Formation Damage Caused by a Water Blockage Chemical: Prevention Through Operator Supported Test Programs
Authors: Nasr-El-Din H. A. , Lynn J. D. , Al-Dossary K. A. 
Published: December 2007

Abstract
Recently, a Saudi Arabian well producing out of a carbonate reservoir was squeezed with a scale control chemical (a phosphonate-based inhibitor). The target zone has a low permeability of nearly 20 mD. The treatment adversely affected oil production, and the damage was attributed to water blockage after the treatment. Several solvents that can remove water blockage were tested, including ethylene glycol monobutylether (EGMBE) and a proprietary chemical designated as E-2. The latter chemical is a patented blend of glycol ethers and has been proven successful in many field applications in the North Sea environment. The chemical is typically applied as a 15 percent by volume mixture in appropriate brines. On this occasion, however, the vendor recommended the chemical be squeezed "neat" into the formation. Concerns as to the effectiveness of the chemical as well as concerns about the cost caused the authors to question the use of the chemical "neat".
In house laboratory test programs demonstrated that using the "neat" E-2 chemical would have resulted in severe formation damage from two newly identified mechanisms. The first is precipitation of salts from the formation brine, and the second is the formation of a tight, stabilized emulsion with the native crude oil, possibly stabilized by the precipitated salts. These additional problems would have exacerbated the water blockage problem. The chemical E-2 precipitated salts even when it was co-mingled with the field mixing water. Phase separation of salts was noted at room temperature and reservoir temperature (200-220°F). By comparison, the use of the "neat" EGMBE did not result in precipitation of salts nor emulsion formation.
Core flood studies confirmed loss of oil production due to water blockage where relative permeability to oil deceased by nearly 50%. In addition, testing of the neat E-2 chemical showed a loss of approximately 85 percent of the original permeability of reservoir core samples, following treatment. This significant drop in relative permeability to oil was attributed to the formation of a tight emulsion stabilized by precipitated salts.
The use of the E-2 chemical at 15 percent concentration was compatible with the formation brine and the field mixing water. It also showed a significant recovery of permeability, however, the efficiency was no better than the EGMBE. Surface tension measurements, and water blockage studies all confirm the effectiveness of the E-2 chemical up to 15 volume percent. E-2 has not been shown to be a cost effective alterative in most applications on Saudi Arabian carbonates. In house evaluation of this chemical prevented extensive formation damage, and resulted in the development of a non-damaging and a cost effective treatment.
The Environmental Impact Assessment from Administrative Obligation to a Real Management Tool
Authors: Sutton C. , Morillon A. , Murray M. , Vidalie J. F. 
Published: December 2007

Abstract
In addition to its administrative purpose, the Environmental Impact Assessment (EIA) is a real management tool for projects and development studies.
This integrated approach consists in a process of continuous assessment and must include firstly, a set of environmental measures representing a contractual basis for the development and the construction phase and secondly, a genuine commitment for the future exploitation phases.
Several examples of recent field developments (including deep offshore projects) are presented as case studies to demonstrate the approach used to fully integrate the preparation of the EIA into the project engineering process and the benefits that can be achieved from it.
The key environmental issues for those projects are defined during the concept selection/definition phase by means of a first emissions assessment and an independent environmental review or preliminary EIA. In this process, the good knowledge of the environment through site surveys is fundamental. Formal EIA studies are then initiated simultaneously as the other Basic Engineering activities. The first phase of work encompasses an identification of gaseous and liquid emissions and wastes, and is then immediately followed by an analysis of the impacts. This provides detailed environmental information to the engineering team at a very early stage of the Basic Engineering process.
The first draft of the EIA is issued shortly before the completion of Basic Engineering and the final version completed prior to starting the formal procedure of the administrative approval.
The key for the success of such an approach is good planning, detailed preparation and the successful early integration of Environmental Specialists into the project teams.