bluuebunny/crossref_metadata_2025 huggingface dataset:
Liquid Unloading in a Big Bore Completion: A Comparison Among Gas Lift, Intermittent Production, and Installation of Velocity String
Authors: Arachman Fitrah , Singh Kalwant , Forrest James K. , Purba Monas O.
Published: December 2007

Liquid loading is a serious problem in low-pressure gas wells. Liquid accumulation in gas wells with inadequate energy to lift the liquid from the wellbore can cause a well to die prematurely.

Various technologies are available to prevent liquid loading in gas wells. They include gas lift, intermittent production, and the installation of a velocity string. Each has applications and limitations for certain well and production conditions. Installation cost and operating cost are also important considerations in choosing the appropriate technology.

This paper presents a comparison among these three different technologies applied to a low-pressure gas condensate well with big bore completion. At the early stage of production, a gas well with a big bore completion will allow high production rates (> 100 MMscfd). As reservoir pressure declines, liquid hydrocarbons and water precipitate may cause liquid loading in the wellbore. Thus, it will require more effort to unload the well. Installing a velocity string will increase the gas velocity, which will prevent liquid loading. The optimum length, diameter and position will be determined based on calculated minimum gas velocity. Gas re-injection will be based on injection rate, and period, as well as method, through tubing or annular.

This study focuses on showing the best solution to obtain optimum gas recovery from both a technical and economical viewpoint. This study uses published information from the Arun field as an example, but it is applicable to any low-pressure gas condensate field with a big bore completion.
Combination of Snake Well Design & Smart Completions: Key Enablers for Champion West Development
Authors: Johan Aidiradiman Haji , Schrader Kirby
Published: December 2007

This paper describes the combination of the snake well concept and intelligent completions, the introduction of which became the key enablers in developing the Champion West field. The field is characterized by uncertain fluid fills, thin multi-layered and intensely faulted reservoirs with complex fill distributions that include thin oil rims below large gas caps. The key success factors for such a development are the integration of multi-discipline approach in optimising the best development plan, real time interpretation of "reverse" logs, managing the mud rheology, records of drilling parameters for torque and drag and lastly but not the least, the robustness and flexibility of the completion design. All of the above are significantly beneficial as lateral learnings and findings for the Champion West Phase 2 & 3 development plan.
Mitigating Gas Hydrate Related Drilling Risks: A Process-Knowledge Management Approach
Authors: Prassl W. F. , Peden J. M. , Wong K. W.
Published: December 2007

In order to secure future energy needs, exploration for hydrocarbon reservoirs occurs increasingly in Arctic and Deep Water Environments. These two drilling environments establish temperature-pressure conditions that are favorable to gas hydrates. Gas hydrates are crystalline complexes of water molecules, which trap gas molecules of suitable size inside their lattice structure. If they are created inside the well system, they may block the BOP or lines, which leads to well control risks. When gas hydrates exist naturally inside formations, drilling activities may lead to their dissociation, which can result in borehole stability problems, serious well gasification or subsequent well integrity problems on production.

To mitigate these drilling risks a Process-Knowledge Management System (PKMS) has been developed. This PKMS allows the capture, verification, and intelligent use of explicit and tacit knowledge, and is constructed to allow exploitation of the knowledge from multiple field experts, company best practice policies, and latest technological findings. To incorporate and use the knowledge sources with embedded uncertainties, type-2 fuzzy set theory is applied. The PKMS is realized through individual reasoning blocks that set up a coherent reasoning lattice. The benefits of this approach are: An easy adaptation and upgrading of the system's knowledge, andSensitivity for selection of particular reasoning blocks, depending on the current drilling scenario and conditions, is sustained.

For the process of drilling within gas hydrate prone environments, the PKMS is actuated with multiple numerical simulations and gas hydrate related considerations. This paper discusses briefly the basic structure of the developed PKMS, as well as the numerical models used to describe the transient temperature field, the pressure profile and the gas hydrate kinetics applied.
Holistic Field Evaluations Improve Prospect Opportunities
Authors: Shelley Bob , Lehman Lyle , Grieser Bill
Published: December 2007

A holistic or overall reservoir performance perspective is seldom used in the well planning/decision process. The industry has a tendency to use broad generalizations along with uncertain interpolated reservoir information. Geologic complexity tends to turn these generalizations and assumptions into less-than-acceptable potential prospect performance predictors. In addition, the industry has a tendency to evaluate the reservoir and well drilling/completion process from a segmented or compartmentalized perspective. Numerous examples of this process exist. Petrophysicists, reservoir engineers, geologists, and drilling and completion engineers perform discrete evaluations based on their training and experiences in other reservoirs. Service companies are given incentives to concentrate on delivery/service issues and product revenue. Consultants focus on developing specific niches or completing assigned tasks. Single wells are analyzed rather than trying to understand how the well fits within the entire reservoir. Many operators grade themselves on their ability to drill and complete for less than industry standard. Their focus is on well cost.

What the industry needs is an understanding of how all these issues fit into the big picture. The subject of this paper is a summary of field evaluations performed to provide a holistic perspective. Results are presented that show how these efforts have identified significant reservoir opportunities with resulting productivity and prospect economic improvement.

The evaluations presented in this paper are holistic in nature and were performed by a team of experts. These evaluations consist of field data quantification, integration, enhancement, statistical and visual analysis, dimension reduction, and development of a predictive artificial neural network (ANN) model. The ANN model is used to identify patterns and trends related to the geology and to reservoir and well completion issues. Economic assessments of various completion/stimulation methods are presented. Engineering evaluations are performed to resolve difficult interpretation issues and test conclusions. The resulting information was then used to drive changes in well completion/stimulation procedures, which in some cases doubled the prospects value. This paper will illustrate the benefits of taking a holistic approach to field-wide problem solving.
Electrical Transport Properties of Fluids Saturated Porous Rocks by 2D Lattice Gas Automata
Authors: Guo Tao , Yue Wenzheng , Li Baoton , Fang Chaoliang
Published: December 2007

We have studied the electrical transport properties of porous media and the physical meaning of Archie's parameters with 2D Lattice Gas Automata (LGA). Based on our simulations we have developed a set of new equations to calculate fluid saturation from electrical measurements. The calculations from the new equations show very good agreement with laboratory measurements and published data.
Using a Modified Brooks-Corey Model to Study Oil-Water Relative Permeability for Diverse Pore Structures
Authors: Goda H. M. , Behrenbruch P.
Published: December 2007

Understanding the significance of apparently different relative permeability relationships is paramount in the assessment of recovery efficiency for a particular field. Apart from the normal difficulties encountered in measuring relative permeability, Australian rocks tend to exhibit considerable diagenesis, often showing clay-filled pores (kaolinite or dickite). This means that fines movement and other related phenomena are often encountered, leading to non-representative testing results.

More generally, relative permeability is a function of several key parameters: pore-scale geometry (including porosity and permeability) and pore distribution (pore-scale heterogeneity), rock-fluid interaction (mineralogy, capillarity and wettability), initial fluid saturation distribution, and fluid velocity (or capillary number, when combined with fluid viscosity and interfacial tension). In some cases more severe heterogeneity, e.g. layering or fractures, may be manifested. Also, defining suitable relative permeability relationships for a particular field requires validation and integration, particularly when conflicting data is available.

This paper introduces a new Brooks-Corey type approach to study relative permeability data for diverse rock types, for both onshore and offshore Australian fields, with particular emphasis on geological aspects. Data from several fields and laboratory tests have been analysed, covering standard testing methods. General conclusions are presented regarding validation and integration procedures. This analysis is believed to be unique in terms of the wide range and amount of data analysed for Australian fields. As an aid to understanding, extensive use has been made of petrographic images, and some of these are presented.
Impact of Dynamic Simulation on Establishing Watercut Limits for Well Kick-off
Authors: Mantecon Juan Carlos , Andersen Iris , Freeman David , Adams Mark
Published: December 2007

Dynamic well modelling can provide additional understanding and an improved process to: ensure a well is going to naturally flow during initial kick-off, and/orpredict the watercut limits for the restart/kick-off of natural flowing wells after a shut-in period.

As reservoir pressure declines and watercut increases, naturally flowing wells often require gas-lift (artificial lift) in order to 'kick-off' and flow them continuously. These wells will generally encounter kick-off problems at a lower watercut than their natural flow limit due to fluid segregation effects in the wellbore under static conditions. Therefore determining the kick-off limit is of primary importance to determine the optimum gas-lift (artificial lift) implementation schedule and its economic impact.

Static (steady state) well modelling is of limited use in being able to predict the effects of fluid segregation on kick-off. Dynamic modelling of the wells during kick-off, however, will indicate the associated flowing tubing head pressure (FTHP) that will enable the well to attain steady state flow as a function of well productivity index (PI), reservoir pressure and watercut.

This paper describes how dynamic modelling of four undersaturated oil fields using OLGA 2000 has been used to effect timing decisions of gaslift installation.

In order to verify that OLGA 2000 was a reliable tool for the simulations, total mass flow rates (oil, water and gas) from well test data were compared with the mass flow rates predicted by OLGA 2000. The OLGA models were able to match the well test data, providing some evidence that OLGA 2000 can be used to model well behaviour.

Dynamic well modelling has been found to be a useful tool in optimising costly gaslift installation timing and improve well completion design. This should minimise potential deferred oil production and optimise reservoir recovery. Dynamic modelling is also useful in identifying and understanding the key flow assurance issues during the well's life cycle.

The time at which the wells will not naturally kick-off is dependent on productivity index (PI), reservoir pressure, and watercut. The reservoir fluid properties are critical to the results.

For the four oil fields studied, it was found that wells were predicted to experience kick-off problems at significantly lower watercuts – anywhere up to 26% less, than for steady state flow.

Dynamic well modelling should be considered during the early phases of concept selection studies to implement gaslift in oil fields.
Remote Field Control and Support Strategy - Umbilicals versus Control Buoys
Authors: Christiansen P. E. , McKay S. A. , Mullen K. , Upston L. R.
Published: December 2007

This paper addresses the latest developments in remote field control strategy and focuses on long distance umbilical control versus the use of a control buoy located over the field. The paper provides an insight into both the technology and also the commercial key drivers for the selection of control strategy.

The historical development of umbilicals and control buoys is summarised. The relevant technologies are described, covering aspects such as buoy design, telecommunication options, onboard power, fluid storage and injection capabilities, operational issues including access and maintenance, and opportunities for workover activities. The discussion is supported by case examples drawn from a number of fields around Australia.
Water-Based Insulating Fluids for Deep-Water Riser Applications
Authors: Javora Paul H. , Wang Xiaolan , Stevens Richard , Pearcy Rick
Published: December 2007

Uncontrolled heat transfer from production tubing to outer annuli, especially in deep-water riser sections, can cause the deposition of sludge, paraffin and asphaltene materials and contribute to the formation of gas hydrates. It also can limit the shut-in time if there is a need to shut down the well for remedial operations. Generally, deep-water risers can be insulated externally, or alternatively, insulated by placing nitrogen gas into the riser annulus. In recent years, a new water-based thermal insulating fluid system with superior thermal properties has been developed and used in field applications. This new system provides an ideal rheological profile to significantly reduce fluid convection caused by temperature differential and to facilitate fluid placement into the riser annulus. This system has been successfully used as an alternative to the current insulation method in deep-water risers in the Gulf of Mexico.

Laboratory-scale equipment and a full-scale test well were constructed to evaluate the thermal insulation properties of fluids. This paper will detail both testing procedures and methods. Steady-state heat transfer and cool down test results on the new insulation fluid will be reviewed for both set-ups. The results will be discussed along with the results from similar tests on conventional brine based packer fluid, current insulation fluids, as well as nitrogen (air) and argon. The full-scale test data will be discussed in relation to modeling wellbore heat transfer. Field cases in GOM are also summarized to demonstrate the effectiveness of this fluid system.
Maximising the Value of the North West Shelf Project Using the DIME Forecasting and Optimisation Tool
Authors: Yates Darren , Chong Lawrence , Dale-Pine Brigitte
Published: December 2007

The North West Shelf Venture Project (NWSP) produces LNG, domestic gas, condensate and LPG's for supply to a variety of customers in the Asia Pacific region. The integrated nature of the Project provides a key competitive advantage through being able to optimise the complete supply chain from reservoir to sales. Gas and liquids are produced and processed offshore with final treatment onshore to meet the required product specifications.

The challenge faced by the Venturers that own the NWSP is to optimise the current and future development of the North West Shelf assets to maximise value for venture owners and all its stakeholders e.g. Government. The reservoir portfolio is becoming increasingly complex and includes fields which have been in gas recycle mode to maximise liquid recovery, and fields that will in the near term and long term require compression to increase deliverability and access low pressure reserves and undeveloped oil & gas fields that represent opportunities to accelerate liquid production.

To facilitate Project wide optimization, Woodside Energy Limited, the operator, has developed a hybrid linear programming optimisation tool, DIME, (Data Integrated Management Environment) to generate long term production and cost forecasts. This paper outlines the far reaching impact of the development and use of DIME within the supply development division of the North West Shelf Venture, NWSV. To fully realize the strategic benefits of the tool the business processes, individual roles, skills and organisational structure of the supply development division have evolved with the DIME technology. A dedicated optimisation group facilitates the forecasting process & system optimization interfacing with key stakeholders from technical experts to the product marketing groups.
Multi-Rate Testing for Vertical Wells in Naturally Fractured Reservoirs
Authors: Tiab Djebbar , Boulenouar Djilali
Published: December 2007

Naturally fractured reservoirs are prolific producers since fractures provide the main path for fluid flow towards the wellbore. Conventional drawdown and buildup tests are not always practical due to various technical difficulties to maintain a constant flow rate during a drawdown test or the loss of production during the shut-in period of a buildup test. In this case multirate tests represent a practical and effective alternative. This paper presents a complete multi-rate test analysis methodology in naturally fractured reservoirs.

The convolution theorem was used to accommodate the change in the rate if the test is multirate. The integral method is used if the rate is continuously changing. It was found that the pressure derivative provides a powerful tool for analyzing multirate pressure transient tests. The Tiab's Direct Synthesis (TDS) technique, which uses exact analytical solutions to obtain reservoir parameters, was applied to different possible cases and the results were compared to those obtained from the other conventional techniques.

In the case of long series of constant flow rate, the log-log plot of pressure and pressure derivative using equivalent radial time or equivalent linear time give approximately similar results. If the wellbore storage effect is large, the error in the permeability (especially during the early radial flow) is greater mainly if the late radial flow is not observed. When the early radial flow is missing, the dimensionless storage capacity ratio ? and the interporosity flow parameter ? cannot be estimated using conventional methods. In such case, they can be determined only from the pressure derivative plot using the TDS technique. During a multirate test, the changing flow rate must be systematically recorded since it is an integral part of all the analysis equations.

Several examples were solved to illustrate the use of the techniques developed. The results show that the multiple rate tests and the TDS technique can be successfully used to characterize naturally fractured reservoirs.
Identifying Reservoir Fluids by Wavelet Transform of Well Logs
Authors: Yue Wenzheng , Tao Guo , Liu Zhengwu
Published: December 2007

The wavelet transform method has been applied to logs to extract the information on reservoir fluids. In addition to time(depth)-frequency analysis generally performed by the wavelet method, we have also performed energy spectral analysis for time-frequency domain signals by the wavelet transform. We have processed 42 models from an oil field in China using this method and subsequently have applied these rules to interpret their reservoir layers. It is found that identifications using the new method are in very good agreement with the results of well tests.
An Integrated Efficient Approach To Perform IPTT Interpretation
Authors: Xian C. , Carnegie A. , Al Raisi M. R. , Petricola M. , Chen J.
Published: December 2007

Interval Pressure Transient Testing (IPTT) with an advanced formation tester has been widely applied to measure vertical and horizontal permeabilities. The principles behind IPTT may appear straightforward. But the interpretation of IPTT in complex reservoirs, such as carbonates presents many challenges, most of which are related to uncertainties arising from the heterogeneous nature of such reservoirs.

A novel, generally applicable approach is proposed for interpretation of IPPT tests. The approach is integrated and efficient, and ensures that the most probably valid and/or valuable information is used and revealed by IPTT. The approach standardizes the complete interpretation procedure of IPTT in a heterogeneous reservoir, using if available, modern wireline logs (such as NMR and Imaging), dynamic data from wireline formation testers and any other relevant information (such as geological description, core data and local knowledge) as constraints on the interpretation. IPTT is also a multi-layer testing technique. An iterative method to define layering is incorporated in the approach to determine the most probable layering. Many types of possible information that can be used to constrain layering definition are classified. Principles and guidelines on using different sources of information to define and refine the layering are recommended. An advanced regression technology is used to get optimized horizontal and vertical permeabilities of reservoir layers. The key is to find as much useful information as possible to guide the regression. To this end, different sources of permeability are classified and used as initial estimates, for input to the regression. Practical skills to perform IPTT regression are also summarized. In many cases, the operating sequences of the formation tester are primarily designed for downhole sampling rather than IPTT. The complicated downhole sampling sequences can make the pressure responses of gauges complicated and noisy. Hence, a Quality Check (QC) procedure is also included into this integrated approach.

Examples from a carbonate reservoir are presented.
Simple Formula for Calculating Strength Degradation of Well Casings and Pipelines Due to Corrosion Pitting
Authors: Sun Kai , Guo Boyun
Published: December 2007

Corrosion develops pits and cavities at the surface of steel structures. Well casings and pipelines in the petroleum industry are subject to severe corrosion because of their exposure to seawater and corrosive fluids that are transported. Under operating conditions, stress concentration around the cavities determines pipe strength degradation that can significantly shorten the life; even cause premature failure of the well casings and pipelines. It is therefore highly desirable to know the stress concentration factor (SCF) for both designing and evaluating well casings and pipelines.

SCF analysis with any numerical method is still a tedious and time-consuming task for ordinary engineers. This paper presents an analytical method to determine SCF around cavities of various geometries at the surface of well casings and pipelines. Results of analyses show that the SCF increases with cavity depth. The SCF value remains between 2 and 3 up to a cavity depth of 0.8 times the pipe wall thickness, and it increases sharply with cavity depth after a 0.8 times of wall thickness is reached. This sharp increase is more significant for thin pipes than for thick pipes.
Zamzama Gas Field - Balancing Risk and Value
Authors: Jackson Mark A. , Jellis Robert G. , Hill Robin , Roberson Paul , Woodall Mark A. , Wormald Glenn , Jafri Naveed
Published: December 2007

The Zamzama gas field is located in the Kirthar Foldbelt, Sindh Province, Pakistan approximately 200 km north of Karachi and importantly, only 8km west of the existing Sui-Karachi pipeline (Figure 1).

Since discovery in early 1998, a number of innovative approaches to field appraisal, gas marketing, infrastructure rationalisation and field development have been undertaken. This has resulted in the successful completion of the initial development phase, Phase 1, with the Zamzama gas plant coming on stream in July 2003. In addition, plans are well progressed towards realising an incremental Phase 2 development.

Cornerstone to the success of development to date has been the implementation of an extended well test (EWT) of the exploration (Zamzama-1/ST1) and appraisal well (Zamzama-2), which came on line in early 2001. The EWT mitigated an entire host of perceived risks associated with a full development, with minimal financial exposure.
The Thylacine/Geographe Offshore Otway Gas Development
Authors: Boardman David W. , Begovich Bryon , Davids Andrew , Kelly Jonathan C. , Rehbock Renita D. , Winters Stephen J.
Published: December 2007

This paper describes the main characteristics of the Thylacine and Geographe gas discoveries in the offshore section of the Otway Basin, and the development plan to commercialise these fields. The paper highlights how the impact of the main subsurface uncertainties has been assessed and used to derive the development plan and reserves distribution. The major subsurface uncertainties affecting the development were found to be gas initially in-place (GIIP), permeability and fault transmissibility.
Alliancing and Partnerships: What we have Learned and Where We are Going
Authors: Robson Simon
Published: December 2007

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'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

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

Application 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

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

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

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

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

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

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

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

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.