bluuebunny/crossref_metadata_2025_split huggingface dataset:
Alliancing and Partnerships: What we have Learned and Where We are Going
Authors: Robson Simon 
Published: December 2007

Abstract
Alliances and partnerships between oil and gas operators and service companies have regularly been reported in the literature over the last 15 years, suggesting they are becoming more common. They were initiated by innovative operators in the late 1980s and early 1990s as a means to increase efficiency and quality, reduce costs, access resources, or align interests (or a combination of these). These new business relationships have quickly been accepted by many service companies. Some alliances have succeeded, some have brought benefits to one party only, and some have failed. Enthusiasm for alliances and partnerships may have waned for some service companies, but a few have persevered, believing there is merit in many of the basic ideas and practices behind these efforts to leverage more mutual value from what can often be an adversarial relationship.
This paper reports on alliancing data since 1990 culled from SPE-published papers. The role and structure of alliances, the operator&#39;s motives, and reported results are analysed to identify trends. From these trends, the future direction for this concept in terms of the type of project and operating company that will potentially most benefit from alliancing is considered.
Risk Reducing Technology and Quantity Competition: The Seismic Story
Authors: Rao Voola Jo. J. , Osaghae Ephraim O. , Khan Javeed A. 
Published: December 2007

Abstract
The new millennium has witnessed large scale mergers of oil companies, thereby bringing about a more concentrated industry. Standard & Poor's (2000) classification included 33 international integrated companies, while Hoover's online (2000) classification lists 50 international integrated companies as the current constituents of this industry. Of particular interest to this paper is the creation of BP plc (1998) (formerly BPAmoco), ExxonMobil Corporation (1999), ChevronTexaco Corporation (2001) and the Royal Dutch/Shell Group of Companies.
The purpose of this paper is to develop the argument that these mergers are a particular form of response to aggressive or excessive exploration behaviour by competing major players, as a means of maintaining their relative standing in the industry. Such relative positioning is of particular importance in an industry where, seven companies, (five American [Exxon, Mobil, Amoco, Texaco and Chevron], one British [BP] and one Anglo-Dutch [Shell]) have long dominated the industry, giving rise to what may be thought of as a mature oligopoly. This paper argues that the mergers of this period were a result of a co-operative move to address detrimental outcomes from competitive behaviour between these major players, particularly for scarce oil reserves. Such competition reduces industry outcomes in terms of profit and players prefer to merge rather than through a competitive shake out that weakens their relative industry standing. Such periodical consolidations have been an integral part of the dynamics of the petroleum industry, particularly in times of excess capacity, leading to price competition and a decline in overall industry profits.
The second major theme that this paper explores is that of the role of technology in causing these outcomes. In particular, the paper traces the development and adoption of newer process technology (cost-reducing technology), specifically 3D seismology. The paper strongly argues that the underlying competitive behaviour between major players in the industry promoted aggressive use of technology, particularly in the late 1990s. Such competition has brought about the presence of excess capacity, followed by intense price competition that has led to worsening outcomes, for which mergers are a solution.
Section II examines the theoretical framework that provides a context to the arguments of this paper. Steindl's (1954, 1976) analysis of the dynamics of imperfect competition is characterised chiefly by technological change or progress coupled with the presence of excess capacity, both of which are pertinent to the argument. Section III outlines the argument in a concrete manner with reference to an industry specific hypothesis, recording the details of the facets upon which the argument hinges. Section IV is essentially a synthesis of the various elements of the arguments and presents an analysis of industry dynamics in the context of a technological change, while Section V consists of concluding remarks.
Matrix Stimulation of Water Disposal Wells Using Viscoelastic Surfactant-based Acid
Authors: Nasr-El-Din H. A. , Al-Mohammad A. M. , Al-Shurei A. A. , Merwat N. K. , Erbil M. M. , Samuel M. 
Published: December 2007

AbstractApplication of matrix stimulation treatments in horizontal wells with openhole completions is a challenging task. Acid diversion is one of the key factors that determine the success of these treatments. This is especially true when the target zone has high permeability streaks. Proper acid distribution in carbonate formations can be achieved by increasing the viscosity of the acid in-situ. This can be done by using polymer/cross-linker or viscoelastic surfactant acid systems. The latter system was selected in the present study because of the tight nature of the reservoir and the presence of hydrogen sulfide in the disposal water. Both factors do not favor the use of polymer-based acids.The surfactant used in the diversion stage is amphoteric. It carries a positive charge in the presence of live HCl acid. Once the acid reacts with the carbonate minerals, the pH of the solution rises and the concentrations of divalent cations (calcium and magnesium) increase. Both factors enhance the viscosity of the solution in-situ. This high viscosity will help in diverting the live acid into other un-stimulated zones. Once the acid stimulation is complete, the high viscosity of spent acid can be broken either by dilution with the injection water or by adding mutual solvent in the pre and post-flushes.Viscoelastic surfactant-based acids have been successfully used to stimulate oil and gas wells over the last three years. This is the first time these acids were used to matrix acidize water disposal wells worldwide. No operational problems were encountered. Injectivity tests conducted after the acid treatment indicated that the treatment removed the damage; iron sulfide, calcium carbonate particles and trapped oil droplets. The skin factor decreased from + 22 before the treatment to nearly zero after the treatment. The pumping rate increased by a factor of three and the injectivity index increased by a factor of 14. The well maintained its injectivity up to the present time (more than seven months after the treatment) and still showing no signs of decline. An additional benefit of the viscoelastic surfactant acid system is its ability to decrease friction losses during acid pumping. Field data are given to support this new benefit.
In-situ In-situ Cross-Linking Acid Diverting Agent (ISCADA): A New Solution to Stimulate Multi-Layered Reservoirs
Authors: Haldar Surajit , Nainwal S. P. , De S. K. , Karmakar G. P. 
Published: December 2007

Abstract
Stimulation of wells completed in multiple layers has always remained a challenge with regards to stimulating all the layers uniformly and effectively. Problems are more severe if the sub-layers of the formation have different petro-physical characteristics and have varying degree of permeability contrast. Stimulation treatments without diversion system applied in these multi-layered wells mainly stimulate the high permeable streaks repeatedly.
PH and temperature sensitive In-Situ Cross-linking Acid Diverting Agent (ISCADA) is developed to temporarily block the high permeable or undesired layers. This diverter chemical with maintained pH is cross-linked in-situ at reservoir temperature. Breaking time of the diverter could be tailor-made by optimizing the breaker depending upon the requirement of treating time. The diverting agent has the advantages of breaking on its own and clearing the blockage of the high permeable zone to regain its initial permeability while facilitates the acid to stimulate the desired zones. The alternating stages of diverting agent, retarded acid and main acid can be designed as per the well conditions.
ISCADA can be applied in both sandstone and limestone reservoirs. Trial application of ISCADA system was done in the limestone formations of Mumbai high field and other sandstone reservoirs. Substantial improvement in productivity observed using ISCADA as diverting agent and subsequent application of compatible acid formulation. Remarkably water production has come down in some wells.
This paper outlines the laboratory development of the diversion stimulation system; case histories of its application in limestone and sand stone reservoirs.
Integrated Reservoir Characterization and Approach for Improving Development Drilling of Narrow Fluvial Channel Reservoir within a Thin Oil Rim
Authors: Xiaoguang Lu , Marmosuwito Sihman , Sincock Bradford W. , Handono Bambang W , Suta Nyoman 
Published: December 2007

Abstract
By integrating geological, seismic data, geochemical mud log data, wireline log correlations, DSTs, reservoir/production data and 3D modeling; a detailed reservoir characterization was conducted in a narrow fluvial channel reservoir within an oil rim. Application of acoustic impedance (AI), generated from 3D seismic inversion, proved to be an effective measure for identifying subsurface sandbody/coal from shale. The sum of negative AI values showing single sandstone in local well region as well as whole sandstone within an oil column was mapped. This provided a sound base for identifying reservoir targets and designing the proposed well to optimally penetrate multiple targets.
During drilling, geologist and geophysicist cooperated together on carrying out a "real time" reservoir study, where the geological model was revised in time, allowing the application of sidetracking a well to improving the successful drilling.
Results of integrated reservoir characterization, in particular the application of AI, have greatly improved the success of development drilling for narrow fluvial channel reservoirs within oil rim.
Simulation of Borehole Failure with Impact of Mud Permeation at Multilateral Junction
Authors: Liu J. X. , Liu J. , Zhu W. C. , Tang C. A. , Yang T. H. , Sheng J. C. , Brady B. H. 
Published: December 2007

Abstract
Implemented into RFPA2D (Rock Failure Process Analysis), a coupled flow-stress-damage (FSD) model is presented to evaluate borehole failure with impact of mud permeation at multi-lateral junction. Specifically, the FSD model that incorporates the small-scale variability in both modulus and strength, is applied to examine the relation between borehole deformation mode and mud weight for boreholes subjected to both internal and biaxial compressive loadings. The multilateral junctions are treated as boreholes with different geometries including circular borehole, elliptic borehole, oval borehole and two adjacent circular boreholes at different positions. The progressive deformation processes of boreholes under incremental mud loading and constant biaxial compressive loading conditions are simulated and the associated failure modes are evaluated. These simulated borehole deformation processes indicate that failure modes are primarily controlled by ratios of the internal pressure (mud weight) to the external pressure in addition to the rock heterogeneity and the borehole geometry. By increasing the magnitude of this ratio, a whole spectrum of borehole deformation modes from unstable (low mud pressure), to stable (intermediate mud pressure), to hydrofracturing (high mud pressure) has been observed. This spectrum for deformation modes provides a basis to determine critical mud pressure to external pressure ratios under which deformation modes switch from unstable, to stable, to hydrofracturing. In this study, the critical ratio under which deformation modes switch from unstable to stable is used to define the lower bound of the safe mud weight window, while the critical ratio under which deformation modes switch from stable to hydrofracturing is used to define the upper bound of the safe mud weight window. Through a series of numerical simulations, the safe mud weight windows have been defined for boreholes at multilateral junction.
Coupled Pore Pressure and Wellbore Breakout Analysis in the Complex Papua New Guinea Fold Belt Region
Authors: Khaksar A. , Warrington A. H. , Magee M. E. , Burgdorff K. L. , Castillo D. A. 
Published: December 2007

Abstract
The Ieru Formation and its underlying shales in the Moran Field in the Papua New Guinea (PNG) Fold Belt region are known for abnormally high pore pressure regimes and severe wellbore instabilities resulting in long non-productive times. The use of pore pressure profiles from conventional log-based methods have shown very limited success in recreating borehole conditions and drilling experiences in wells drilled in the area, particularly in the lower Ieru Formation, because of the tectonic deformation associated with the PNG region. By constructing a geomechanical model consistent with rock strength and drilling conditions, we were able to constrain the pore pressure and stress coupling for the Southeast Moran area. The geomechanical model with pore pressure profile is consistent with the stress and pressure conditions needed to explain wellbore breakout observations from image data and drilling experiences in the original vertical well and its two sidetracks. Using the geomechanical model, we evaluated wellbore stability for the Ieru and reservoir sections in an exploration well in South East Moran Field. A postmortem of the SE Moran-1X well confirmed the accuracy of the geomechanical model, reproducing the borehole conditions seen in image logs and implying the pore pressure-stress coupling is well understood in shales underlying the Ieru Formation and in the reservoir sections.
Hydraulic Fracture Optimization Maintains Original Production Rates in New Wells in a Mature Gas/Condensate Reservoir in Oman
Authors: Giacon Paolo , Casero Alberto , Shaoul Josef , Shueili Ahmed , Al-Harrasi Salim 
Published: December 2007

Abstract
Hydraulic fracturing has been an integral part of the development of two gas/condensate fields in central Oman. These fields supply an LNG plant on the coast at Sur. The producing reservoir is 160-190 meters thick and highly laminated, so fracture height growth and vertical coverage are key issues. There are significant variations in permeability and depletion (following several years of production) between the individual reservoir units. There has been an evolution in the fracturing strategy in terms of the number of treatments pumped per well (going initially from 1 to 5 fractures), the size of proppant used (12/20, 16/30, 20/40) and the size of the pad volume (75 – 350 m3) [Ref. 1].
A new initiative was taken recently to further optimize the fracturing procedures, following up on the results of a comprehensive analysis of several years of treatments [Ref. 2]. In order to mitigate fracture complexity resulting in very high net pressures, pumping rates were lowered from 8 m3/min, down to as low as 2 m3/min. in some cases. To reduce screenouts in the most difficult reservoir zones, 40/70 ceramic proppant was pumped ahead of 20/40 mesh as a proppant slug in most of the jobs. Because of the significant fracture height containment due to the heterolith layers, the practice of trying to stimulate multiple geological units with one fracture treatment was abandoned in favor of stimulating each individual unit separately. This has led to as many as 11 fracture treatments per well. Based on the previous study, which showed that screenouts were not related to pad size and that the initial slurry stages would also create sufficient fracture dimensions, the pad volumes were decreased, leading to improved fracture conductivity. Using smaller pad volumes and a lower pumping rate have reduced complex fracture growth, reducing the number of near-wellbore screenouts as well as net fracturing pressures. Since the fracture stays contained within the reservoir sub-unit, good fracture half-lengths are produced with small pad volumes.
All of these measures have had a positive impact on the post-frac productivity of the newly treated wells, obtaining production rates equal to some of the best initial wells, despite the large amount of depletion in the field. In addition, many of the changes in fracturing strategy have also reduced the cost of fracturing operations, leading to a significant increase in Return On Investment for fracturing expenditures. These results are of interest to anyone working with a thick, laminated formation needing hydraulic fracture stimulation.
Coupled Stress and Fluid Flow Using a Finite Element Method in a Commercial Reservoir Simulator
Authors: Liu Q. , Stone T. , Han G. , Marsden R. , Shaw G. 
Published: December 2007

Abstract
Reservoir simulation traditionally involves prediction of fluid component and pressure profiles over time scales that are typical of oil and gas recovery processes. As commercial reservoir simulators evolve and become more sophisticated and accurate, they are increasingly being applied to marginal fields including reservoirs that have stress dependent problems.
Recently, efforts have been made towards coupling 3-D finite difference elastic stress solutions with fluid flow in a commercial reservoir simulator (SPE 65107, SPE 79697). In this paper the implementation of a finite element method to solve the rock elastoplastic stress equations that are coupled to reservoir fluid flow is introduced. This method has been chosen as an alternative to the finite difference method in order to produce higher accuracy in situations where the finite difference method has unacceptable errors. In addition, a non-isotropic work hardening plastic algorithm has been derived as part of this finite element implementation. Together they provide an improved analysis of weaker, tectonically stressed and faulted reservoirs. Geomechanical issues such as subsidence/compaction, wellbore failure, and the impact of stress-dependent flow parameters that affect fluid production can be modelled.
Advantages and disadvantages of computing the stress coupled to fluid flow by finite difference and finite element methods are discussed. An analysis of error in the two methods, larger scale coupled geomechanical reservoir simulation, solution of the equations and some future directions are included. A workflow is offered that takes into account data collection for the simulator, calibration and interpretation of results. This workflow is important because knowledge of reservoir engineering, reservoir simulation and geomechanical engineering are needed in order to produce a meaningful coupled geomechanical prediction.
Determining the Average Reservoir Pressure from Vertical and Horizontal Well Test Analysis Using the Tiab's Direct Synthesis Technique
Authors: Chacon Abel , Djebrouni Abdelghani , Tiab Djebbar 
Published: December 2007

Abstract
Tiab's Direct Synthesis (TDS) technique is a direct method to interpret transient well pressure tests without type curve matching. This method uses log-log plots of the pressure and pressure derivative versus time to compute reservoir parameters such as permeability, wellbore storage, skin factor, half fracture length, drainage area, distance to the boundaries, storage coefficient and interporosity flow parameter among others. The TDS technique gives accurate results because it uses exact analytical solutions to compute the reservoir parameters.
During the last three decades there has not been a significant advance in well test analysis to determine the average reservoir pressure, and only conventional semilog analysis has been used. As a new concept, this paper extends the TDS technique, which primarily uses the pressure derivative function, to determine the average reservoir pressure for three cases: vertical well in closed homogeneous reservoir, hydraulically fractured vertical well, and horizontal well in a closed anisotropic reservoir. As result, new analytical equations to determine the average reservoir pressure from the pseudosteady state flow regime have been developed.
A new flow regime for horizontal wells has been observed and is referred to here as the elliptical or biradial flow regime. This flow regime has been numerically modeled and incorporated to the TDS technique. Its corresponding characteristic straight line in the pressure derivative plot has a slope of 0.36. It is observed only when the horizontal well penetration, i.e. the ratio of the well length (Lw) to the reservoir width (hz) or Lw/hz, is between 0.10 and 0.70. The elliptical flow regime is very useful to compute the geometric average horizontal permeability or the effective horizontal penetration length, when the pseudoradial flow regime (also called late radial) is not well defined or the test was not run long enough to observe it in the pressure derivative plot.
Procedures to determine the reservoir properties and the average reservoir pressure for each case are presented in detail for field and simulated examples.
Why Is GTL So Expensive?
Authors: Seddon Duncan 
Published: December 2007

Abstract
There are many proposals to utilise GTL (gas to liquids) technology to develop gas fields (so called monetization of stranded gas). Despite worldwide interest, there are only two commercial operations with possibly another two in advanced engineering feasibility stage.
In an attempt to understand why so many schemes remain undeveloped, this paper presents a series of concept studies for GTL schemes on a comparable economic basis. A fixed variable relationship is presented which relates the cost of production of the GTL products to cost of the feedstock gas.
Most schemes utilise the Fischer-Tropsch (FT) process to convert gas into a syncrude or derivative such as diesel fuel. The existing commercial plants have high production costs and are uncompetitive unless the gas price is below $0.50/GJ. Newer approaches improve this, but the lowest cost is still likely to require gas below $2/GJ to be competitive with conventional fuels based on oil at $30/bbl. Nevertheless, FT schemes can make sense in niche (tax driven) situations.
Some FT schemes generally aim to maximise added value by producing and selling high valued waxes or lubricants. This increases the complexity and capital cost and is limited in scope by the size of the product market.
An alternative approach is the conversion of gas into methanol. This is widely practiced in the chemical industry, but in GTL, entirely offshore facilities are envisaged. Such schemes have technical hurdles and to be competitive with onshore facilities require gas at $1/GJ or less. The production cost of the methanol derivative, DME, is similar.
Methanol can be converted into olefins. and hence easily processed into high value polymer and resins for which there is a large and growing market. The route Gas-to-Resin – a gas to solids route – could potentially produce a competitive product with gas prices as high as $3/GJ.