bluuebunny/crossref_metadata_2025 huggingface dataset:
Developing and Maintaining a High Performance Culture in a Well Engineering Environment-Making Technical Limit Work
Authors: Gallagher K. T. , Jones G. D.
Published: December 2007

Pursuit of performance is fundamental in today's Well Engineering world but are you getting all that you can out of your team? Detailed procedures and systems, incentives and initiatives are often used but the real key may be something else-the people and the organisational culture that they work within.

It has been 10 years since the introduction of Technical Limit1, and in the interim human resource specialists have widely argued that people are the sole source of sustainable competitive advantage in an organisation rather than systems and processes2. Translating this to a well engineering environment, our people should no longer be considered a commodity item. Issues such as performance management, training and development, organisational learning, developing a performance mindset (culture), and the ability to build individuals into a cohesive team all affect drilling and completion performance. These issues are often highly interdependent; such is the complexity of managing people.

We believe that by taking the learnings from years of Technical Limit application and coupling them with current thinking in developing a high performance workplace culture, the result yields a high performing drilling and completions team.
Managing Wellbore Instability Risk in Gas-Hydrate-Bearing Sediments
Authors: Tan C. P. , Freij-Ayoub R. , Clennell M. B. , Tohidi B. , Yang J.
Published: December 2007

With the petroleum industry endeavouring to develop oil and gas fields in deepwater and to increase its activities in onshore arctic environments, greater emphasis should be placed on quantifying the hazards to drilling operations posed by gas hydrates. In spite of gas hydrate-bearing sediments having been drilled successfully in the past, it is important, as future drilling operations progress into deeper and ultradeep waters, to develop a sound understanding of gas hydrate-related hazards and thereby identify ahead of time when problems are likely to occur. It is also highly desirable to define the envelope of risk-free operations so that unnecessary costs and delays associated with mitigation of the problems are not incurred.

This paper describes the specific requirements to develop a comprehensive risk management capability for drilling in gas hydrate-bearing sediments. The methodology adopted concentrates on reducing risk and uncertainty associated with gas hydrates and associated shallow gas geohazards in deep water. These will be achieved by means of determining the petrophysical, mechanical and thermodynamic properties of gas hydrate-bearing sediments, and developing a fully coupled model for wellbore stability in the sediments, and methodology for drilling fluid design optimization and a risk assessment and optimization framework. Examples of laboratory measured petrophysical and mechanical properties of gas hydrate-bearing sediments, and results of time- dependent wellbore stability in such sediments are presented and discussed.
Gulf of Mexico Deepwater Well Completion with Hydrate Inhibitors
Authors: Pakulski M. , Qu Q. , Pearcy R.
Published: December 2007

Utilization of low-density completion fluids and packer fluids is becoming more popular in oilfield deepwater operations. These low-density fluids must first meet the expected nonformation damage aspect, found with clear brine fluids, and consequently not impede future gas or oil output from wells. However, formulation of such fluids has some unique challenges to overcome in the deepwater environment. Especially for completion fluids in deepwater wells, they have to work under significant pressure regimes and low mudline temperatures, conditions favoring the formation of gas hydrates. Methanol is the only known thermodynamic hydrate inhibitor allowing formulation of a low density and hydrate protected fluid, while glycols and salt solutions can add undesired density to the fluids. On the other hand, high volatility, toxicity and flammability of methanol make this chemical a necessary "evil" in oilfield applications.

In the particular case reported here, a multiwell deepwater project located in a Gulf of Mexico (GOM) deepwater area required a low-density packer completion fluid to optimize operational requirements and the operator insisted the usage of methanol be limited or possibly eliminated. With the particular reservoir pressure and low mudline temperature, as low as 1.67°C (35°F), the gas/fluid system was severely at hydrate conditions. Commingling a Low Dosage Hydrate Inhibitor (LDHI) being a combination of thermodynamic hydrate inhibitor (THI), kinetic hydrate inhibitor (KI) and antiagglomerant (AA) with a low-density fluid was a viable solution to the problem. A novel low-density packer fluid containing a long lasting LDHI was invented for the application.

Working with the new fluid is a safer alternative; the fluid is more acceptable than the high methanol product. The hydrate-inhibited system was placed inside the annulus as packer fluid in a unique fashion and in coordination with other packer fluids. This novel placement method has been applied in multiple GOM deepwater wells. This paper highlights the development of the hydrate inhibitive packer fluid technology and its successful field application.
Controls on Fracturing in Carbonate Rocks
Authors: Peacock D. C. P. , Mann A.
Published: December 2007

Sedimentology (lithology, sedimentary structures, bed thick-ness, mechanical stratigraphy, the nature of bedding planes), structural geology (tectonic setting, palaeostresses, subsi-dence/uplift history, proximity to faults, position in a fold, timing of structural events, mineralisation, the angle between bedding and fractures) and present-day factors (orientations of in situ stresses, fluid pressure, perturbation of in situ stresses, depth) can all control the nature and distribution of fractures within carbonate rocks. Understanding these factors requires traditional geological skills, including the analysis of core, borehole images and exposed analogues.
Evaluation of Cationic Water-Soluble Polymers With Improved Thermal Stability
Authors: Fernández I. J.
Published: December 2007

Acrylamide-based water-soluble polymers are used in operations such as drilling, water flooding and water conformance. A drawback of these polymers is that the primary amide group is sensitive to hydrolysis at elevated temperatures. This fact sometimes becomes a problem in deep reservoirs, because the solutions properties change when the degree of hydrolysis of the polymer increases and, in a media of high salinity and water hardness, the precipitation of the polymer may occur.

To improve the thermal stability different copolymers have been prepared. The comonomers used for this purpose are mainly N-alkyl substituted acrylamide derivatives and of particular importance N-vinyl pyrrolidone (NVP). The aim of the present work is to evaluate the improvement of the thermal stability of cationic water-soluble polymers based on acrylamide when NVP is introduced as a comonomer, in order to know the amount and kind of incorporation of NVP required to get a polymer useful for applications under severe conditions of temperature.

Several copolymers and terpolymers of acrylamide, a cationic monomer and NVP were prepared. The products were evaluated in terms of the thermal stability of the primary amide group and the fraction of retention of the intrinsic viscosity in aging tests at 248°F. The introduction of NVP limited the hydrolysis of the primary amide groups. When the content of NVP increased in the terpolymers the hydrolysis degree reached after the aging was lower. In addition, the distribution of the monomers in the polymer chain also showed an influence in the improvement of the thermal stability. The results made possible to suggest a mechanism for the stabilization of the amide group by NVP.

These results provide information to prepare a cationic water-soluble polymer that could be used for applications where severe temperature conditions are expected.
Modeling of Geomechanics in Naturally Fractured Reservoirs
Authors: Bagheri M. , Settari A.
Published: December 2007

Conventional modeling of fractured reservoirs treats fracture system permeability and porosity as static (or pressure-dependent) data. Recent attempts at coupling geomechanics focused on the permeability, but used crude empirical relations and treated the fluid flow as single porosity. This study takes advantage of joint mechanics theory to develop general, rigorous coupling between fluid flow equation and deformation of fractured media. Both porosity and perm-eability coupling is considered.

The geomechanical part uses the equivalent continuum approach, considering both rock and fracture deformation properties. Multiple sets of fractures with any dip and strike angle can be defined. The stiffness of fractures varies with the effective stress according to a law typical for joints. The resulting pseudo-continuum stiffness matrix equations were verified by comparing with models using explicit modeling of fractures and analytical anisotropic poroelasticity theory.

The main novelty of this work is that the geomechanics solution is decomposed into matrix and fracture parts and used to compute their dynamic porosity and permeability separately. This approach captures rigorously the effect of fractured media deformation on the dual porosity flow part of the coupled system, and allows the permeability and porosity variations to be based on measurable joint properties. Generally, fracture deformations produce changes of the permeability tensor in both magnitude and orientation, which in turn influences reservoir flow and compaction behavior.

The main issue studied was the variation in the permeability of the fracture system. The examples show that fracture deformation has a significant effect on productivity or injectivity, and that anisotropy of the permeability tensor develops from deformation. The results provide an initiative for implementing the case of full tensor permeability.
Faster and More Accurate Data Collection for Microbiologically Influenced Corrosion
Authors: Zhu X. , Kilbane J. J.
Published: December 2007

Microbiologically Influenced Corrosion (MIC) is a significant problem affecting the oil and gas industry, particularly in production operations. The most commonly used means of monitoring MIC is to quantify the number of bacteria capable of growing in various microbial growth media after inoculation with water samples obtained from pipelines/production operations. However, it is becoming increasingly apparent that the number and type of bacteria present in environmental samples, as measured by microbial growth tests, does not correlate well with the presence or extent of corrosion in pipelines, and that microbial growth tests are slow and inaccurate. To address this issue GTI has developed genetic techniques to characterize the types and abundance of bacterial species present in oil and gas production operation samples more quickly and with greater accuracy than was previously possible. The ability to obtain MIC data faster and more accurately will assist the oil and gas industry in better understanding and controlling MIC.
A Review on Recent Advances in the Numerical Simulation for Coalbed Methane Recovery Process
Authors: Wei X. R. , Wang G. X. , Massarotto P.
Published: December 2007

The recent advances in numerical simulation for primary and enhanced coalbed methane (CBM/ECBM) recovery processes are reviewed, focusing primarily on the progress that have occurred since a similar review paper was published by King and Ertekin in 19891,2. Two major issues regarding the numerical modeling will be focused on in this review: firstly, multicomponent gas transport in in-situ bulk coal and secondly, changes of coal properties during methane production. For the former issues, a detailed review of more recent advances in modeling gas and water transport within coal matrix is presented. Further, various factors influcing gas diffusion through coal matrix will be highlighted as well, such as pore structure, concentration and pressure, and water effects. An ongoing bottleneck for evaluating total mass transport rate is developing a reasonable representation of multi-scale pore space that considers coal type and rank. Moreover, few efforts have been involved to model water flow behavior in coal matrix and its effects on both CH4 production and on the exchange of CO2 and CH4. As for second issue, theoretical coupled fluid flow and geomechanical models have been proposed to describe the evolution of pore structure during methane production, instead of traditional empirical equations. However, there is currently no effective coupled model for engineering applications. Future perspectives of developing suitable simulation models for CBM production and predicting CO2-sequestration ECBM recovery are suggested.
Accurate Modeling of Matrix-Fracture Transfers in Dual-Porosity Models: Optimal Subgridding of Matrix Blocks
Authors: Famy C. , Bourbiaux B. , Quintard M.
Published: December 2007

This paper proposes a sub-gridding technique to improve the reliability of matrix-fracture exchanges predicted by dual-porosity simulators. As a preliminary target, this sub-gridding technique was designed for the capillary imbibition case, by taking into account the physical specificities of this mechanism while minimizing the computational cost. Very accurate exchange terms are obtained, showing interesting perspectives of application of this modelling methodology.
Quantifying Petrophysical Uncertainties
Authors: Adams S. J.
Published: December 2007

Typical petrophysical deliverables for volumetric and modeling purposes are net reservoir, porosity, permeability, water saturation and contact locations. These data are usually provided without quantitative determination of their uncertainties.

Current computing power renders it now feasible to use Monte-Carlo simulation to determine the uncertainty in petrophysical deliverables. Unfortunately, quantitative uncertainty definition is more than just using Monte-Carlo simulation to vary the inputs in your interpretation model. The largest source of uncertainty may be the interpretation model itself.

This paper will use a variety of porosity interpretation models to illustrate how the impact of each input on the uncertainty varies with the combination of input values used in any given model. It will show that use of the incorrect model through oil and gas zones may give porosity estimates with Monte-Carlo derived uncertainty ranges that exclude the actual porosity.

Core data provides the best means of quantifying actual uncertainty in the petrophysical deliverables. Methodologies for deriving uncertainties quantitatively by comparison with core data will be presented. In the absence of core data, interpretation models should have been tested against core data through the same or similar formations nearby. Monte-Carlo simulation can then be used as an effective means of quantifying petrophysical uncertainty. Comparisons between the core comparison and Monte-Carlo techniques will be made, showing that similar results are achieved with the appropriate interpretation models.

The methodologies described in this paper are straightforward to implement and enable petrophysical deliverables to be treated appropriately in volumetric and modeling studies. In addition, quantification of petrophysical uncertainty assists in operational decision-making by letting users know how reliable the numbers produced actually are, and what range of properties is physically realistic. Such work also allows the key contributions to uncertainty to be defined and targeted if overall volumetric uncertainty must be reduced.
Development and Introduction of Heavy Organic Compound Deposition Diagnostics, Prevention and Removing
Authors: Voloshin Alexander I. , Ragulin Victor V. , Telin Alexey G.
Published: December 2007

One of the major unsolved complex systems confronting the petroleum industry at present is the untimely depositions present in oil.

Deposition of asphaltene, resin and paraffin at the formation bottom-hole zone refers to less controlled processes. The paper discusses a integratid approach to forecasting asphaltene, resin, paraffin precipitation in the formation bottom-hole zone, analysis of technological and economic efficiency of bottom-hole zone treatment using oil solvents carried out at the fields of Western Siberia and Volgo-Ural petroleum region.

The method to evaluate the tendency of formation oil to deposit asphaltene, resin and paraffin under the conditions of a sharp change in thermo-baric conditions in the formation bottom-hole zone has been developed on the basis of physical-and-chemical properties of surface oil, namely viscosity, density, quantitative content of asphaltene and resin, refractive index, thermal effects of asphaltene flocculation with the account of geological properties of the petroleum reservoir. Correlation dependencies of oil heavy component composition upon its properties have been found. Maps of a number of fields have been built taking into account the risk of asphaltene, resin, and paraffin deposition. The developed method is used as the basis for choosing candidate-wells for bottom-zone treatment.

To renew well productivity, it is considered optimal and efficient in the conditions of Western Siberia to carry out the bottom-hole zone treatment using hydrocarbon solvents. To date more than 1300 treatments have been carried out at 20 fields.

The theoretical foundation for solvent selection to remove asphaltene, resin, and paraffin deposits in oil wells, pumps, storage vessels, transfer pipelines has been developed on the basis of modern concepts of structure, properties and reactivity of asphaltene and resin, as well as analysis of thermodynamic and kinetic aspects of solvents interaction with petroleum disperse systems.
Risk and Uncertainty Modelling in the Oil and Gas Industry
Authors: Faisal F. , Al-Thani J. , Merna T.
Published: December 2007

The management of risk is one of the most important issues facing the oil and gas industry today. This paper will focus on the need for risk management in the oil and gas industry. A typical project from a major oil and gas producer has been selected and its typical risks identified. The risks are analysed and modelled in the CASPAR (Computer Aided Simulation for Project Appraisal and Review) program. The paper distinguishes between pure risk and spread risk for forecasting the economic parameters of different risk scenarios.

The increasing pace of change, customer demands and market globalisation all put risk management high on the agenda for forward thinking companies. It is necessary today to have a comprehensive risk management strategy. Having a process in place to identify, analyse and manage risks is paramount. The oil and gas industry is fraught with risk and it is necessary for these risks to be assessed continuously.

In this paper, the authors examine the downstream risks inherent in the oil and gas industry and differentiate between the more manageable/quantifiable pure risks such as construction, health and safety and project management and the less manageable spread risks associated with war, terrorism and market demand which affect the price of oil and gas.
Productivity Assessment of Fractured and Non-Fractured Wells in a Lean/Intermediate Low Permeability Gas Condensate Reservoir
Authors: Baig T. , Droegemueller U. , Gringarten A. C.
Published: December 2007

This paper compares the near-wellbore behaviors and productivities of a vertical non-fractured well and a vertical hydraulically fractured well in a low permeability, lean/intermediate gas condensate reservoir, when the flowing well bottomhole pressure falls below the dew point pressure. Under this condition, two phases, reservoir gas and liquid condensate, coexist near the wellbore and a condensate bank is formed, reducing the productivity of well.

Productivity impairment is investigated with single well, fine grid, compositional simulations and analyzes of simulated pressure transient tests.

Reservoir simulation and simulated pressure transient tests show that, in this low permeability reservoir, there is no evidence of capillary number effects, due to low sustainable production rates and high interfacial tension. Effect of production rate and time on well productivity is investigated.

Fracturing the well before the formation of the condensate bank significantly improves productivity. Stimulation reduces the pressure drawdown, leading to less liquid condensate drop-out near the wellbore, thus delaying the formation of the condensate bank. The length of the fracture controls the productivity: a long fracture yields a higher productivity improvement, despite a lower dimensionless fracture conductivity, because the reduction in pressure drawdown far exceeds the pressure loss inside the finite conductivity fracture. Stimulation of the well after the formation of the condensate bank, with a fracture length extending beyond the bank, is also investigated.

Challenges associated with the simulation of hydraulic fractures in gas condensate field studies are briefly discussed.
Scale Inhibitors Designed for Zinc Bromide High-Density Completion Brines
Authors: Wang X. , Ke M. , Qu Q.
Published: December 2007

Zinc bromide high-density brines are widely used in well completions, and zinc sulfide scale, which can cause formation damage and production decline, has been reported in some well completions. When severe scaling occurs, costly acid stimulation treatments are required to restore well production. Therefore, it is highly desirable to add an effective ZnS scale inhibitor directly to ZnBr2 brines before scaling can occur downhole.

While scale inhibition methods for sulfates and carbonates in production equipment and reservoirs have been extensively studied, only limited literature for sulfide scales exists. Of the limited case, most are related to treatment in production tubing and topside process facilities, i.e., low zinc concentration in produced waters. Unlike traditional scale inhibitors which are typically applied in fresh water or very low salt solutions (~3 % salt), inhibitors designed for zinc brines need to be compatible with more than 50% dissolved salt. In zinc brines, the extremely high salt content and the limited amount of free-water severely restrict both the solubility and effectiveness of inhibitor candidates. Furthermore, most wells using high-density zinc brine are high-temperature high-pressure, and conventional scale inhibitor evaluation methods are not adequate. New evaluation methods were developed to test scaling tendencies and inhibition under downhole conditions.

This research work was focused on the development and evaluation of ZnS scale inhibitors compatible with high-density zinc brines. Candidate chemicals were selected based on their potential ZnS scale-inhibition characteristics, and were studied in high-density zinc brines at high temperatures. Details of the test methods and results are presented for several ZnS scale inhibitors.
Multi-Rate Transfer Dual Porosity Modeling of Gravity Drainage and Imbibition
Authors: Donato Ginevra Di , Lu Huiyun , Tavassoli Zohreh , Blunt Martin J.
Published: December 2007

We develop a physically-motivated approach to modeling displacement processes in fractured reservoirs. To find matrix/fracture transfer functions in a dual porosity model we use analytical expressions for the average recovery as a function of time for gas gravity drainage and counter-current imbibition. For capillary-controlled displacement the recovery tends to its ultimate value with an approximately exponential decay.1 When gravity dominates the approach to ultimate recovery is slower and varies as a power-law with time.2 We apply transfer functions based on these expressions for core-scale recovery in field-scale simulation.

To account for heterogeneity in wettability, matrix permeability and fracture geometry within a single grid block we propose a multi-rate model.3 We allow the matrix to be composed of a series of separate domains in communication with different fracture sets with different rate constants in the transfer function.

We use this methodology to simulate recovery in a Chinese oil field to assess the efficiency of different injection processes. We use a streamline-based formulation that elegantly allows the transfer between fracture and matrix to be accommodated as source terms in the one-dimensional transport equations along streamlines that capture the flow in the fractures.4–6
Application of Streamline Method to Hot Waterflooding Simulation for Heavy-Oil Recovery
Authors: Pasarai U. , Arihara N.
Published: December 2007

We extended the streamline method to model hot water-flooding process in a heavy oil reservoir that underwent cold water-flooding. The pressure equation for defining streamlines was derived by summing up the mass conservation equations with compressibility and depletion taken into account. The mass and energy equations in terms of streamline time-of-flight coordinates were solved for each streamline by the Newton-Raphson's procedure based on an implicit single point upwind scheme. The thermodynamic calculations were performed along streamline to account for the changes in properties with temperature and pressure.

The developed simulator was tested for a hot water-flooding simulation in one-dimensional (1D) and two-dimensional (2D) heavy oil reservoirs and verified by comparison with a commercial thermal simulator. Tests showed the ability of the streamline method to simulate the hot water-flooding process with faster calculation speed.
An Alternative for Saving Gas Burnt in Well-Testing Operation by Using MPFM— A Case Study
Authors: Wijayanti H.
Published: December 2007

TOTAL E&P INDONESIE, one of Production Sharing Contractors in Indonesia, manages its field located in East Kalimantan, Indonesia. Under well servicing department, one of its activities in support and service operation is well testing. The scope of work consists of production test, offload, clean up, start up and support data acquisition.

There are some challenges faced in well testing activity, both in environment and operation point of view. In environment point of view, it happens frequently that the tested fluid cannot be routed back to the flow line or production network because of some reasons. Since the tested flow cannot be re-routed, it can only be released to the environment after formerly burnt. So, reducing the amount of gas burnt becomes one of the environmental challenges in well testing.

In operation point of view, the requirement of well testing is increasing from time to time. To fulfill the demand, more testing unit is required from time to time. The testing unit can be a testing barge or a MPFM, either a complete package of MPFM on a dedicated self-propelled barge, or just a portable MPFM unit mounted on other barge with other unit on it (e.g. portable MPFM mounted on slick line barge).

In Tunu – Tambora field, the average volume of annual flaring is approximately 1,900 mmscf. This amount is apportioned among gas burnt resulting from offload, clean up, start up, production test, MRPL, and BPT. Gas burnt from production test, MRPL, and BPT operation is potentially saved by using MPFM. Gas from offload (atmospheric pressure) is also possible to be re-routed to production network with the installation of multiphase pump at the return line.

Potential gas recovered through MPFM based on the percentage of gas burnt resulted from production test, MRPL and BPT is more or less 590 mmscf per year. With this value, approximately US$ 1.5 MM per year can be saved with the assumption that only 80% of the potential gas is recovered.
Knowledge Discovery in Drilling Optimization for Eliminating Surprises
Authors: Bi Xueliang , Yan Tie , Zhang Shurui , Wang Changjiang
Published: December 2007

Drilling process has a nature of surprise and uncertainty. It is urgent for us to decrease the drilling problems and to increase drilling speed. The scale of drilling data is becoming larger and larger. However there are plentiful and valuable knowledge hidden behind them. It is of great benefit to grasp the potential information. It will be beyond people's capacities when artificially analyzing and understanding these data stored in such a great database, so the techniques of knowledge discovery and data mining are arising at the historic moment. Knowledge discovery in drilling analysis, process monitoring and control is a new and important technology. Though still in its infant stage, it shows great application prospects. Its development, present application state and general process are briefly described in this paper. Then the authors analyze the approaches, the application and the theory of data mining and knowledge discovery for drilling analysis, process monitoring and control. Through analyses of characteristics of operational data, the authors also point out the challenges for data mining and knowledge discovery for process monitoring and control and contents to be studied. At last, the application of knowledge discovery in drilling optimization in Daqing Oilfield is analyzed.
Integrated Reservoir Assessment: A Way To Identify "Overlooked" Multilayered Reservoirs
Authors: Nikijuluw R. , Suwito Z. A. , Arianto M. A.
Published: December 2007

Semberah field is an oil and gas field that contains of complex multi-layer reservoirs of deltaic environment. As the field matures, the development strategy and approach have been focused on the smaller reservoirs (each < 5 BCF IGIP), which were probably overlooked in early development stage. Therefore, detail integrated reservoir assessment (geological facies analysis and engineering wellbore evaluation) becomes very important.

The paper will demonstrate a successful case of such integrated assessment in the thinly Fxx sand series, which was overlooked. The initiative assessment was started when there are two thinly sands (9 feet - FxxC and 6 feet – FxxD) penetrated in one of the newly drilled wells, namely well-G. Based on detail geological facies analysis, this Fxx series can actually be divided into 6 different thinly sands, FxxA/B/C/D/E/F. A further production analysis shows that these two permeable FxxC and FxxD sands in well-G are believed to be different from the "water-out sands" in the two offset wells. The perforation was taken from FxxC and FxxD in well-G resulting rate gain 17 MMCF of dry Gas and no Water. Followed with another perforation in one of this series of FxxB in well-E, which is also believed to be different from the ones in well-G, resulted 11 MMCF of gas and no Water.
Managing Uncontrollable and Controllable Uncertainties Using EDA Methods: A Fluvial-Reservoir Case Study
Authors: Peng C. Y. , Gupta R. , Vijayan K.
Published: December 2007

A synthetic but realistic fluvial reservoir case study is used to study the performance of the experimental design and analysis (EDA) methods. A single 3-level fractional factorial design (81 design runs) is selected to capture the likely significant effects from 14 input variables. They consist of uncontrollable subsurface uncertainties (porosity, variograms, channel dimensions, endpoint saturations etc.) and controllable engineering uncertainties (number of wells). Expert opinion regarding the likely significant effects is used as the helpful information in selecting the design matrix. This single design matrix enables the comparison of three output response probability distribution curves generated from three different development scenarios.

A response surface equation model is developed to predict the P90, P50 and P10 values. Unless the equation model is fairly accurate, these predicted percentile values could be uncertain. The prediction error can be large if the design matrix does not pick up majority of the significant effects. To evaluate the developed equation model, cross-validation method and additional test runs are used. In this case study, the 81 run design enables the development of a reasonably good response surface for prediction purposes.

For decision making purposes, bootstrap confidence intervals can be used to quantify the uncertainty at the derived percentile values. Wide confidence intervals at the percentile values mean the predictions are less convincing. With these confidence intervals at the P90, P50 and P10 regions, possible 3D models at such percentile values can be selected, if desired.
A Novel Adaptive Anisotropic Grid Framework for Efficient Reservoir Simulation
Authors: Nilsson J. , Gerritsen M. , Younis R.
Published: December 2007

We present a novel parallel Adaptive Mesh Refinement (AMR) framework for the effective simulation of reservoir simulation processes. The framework is based on a Cartesian Cell-based Anisotropic Refinement (CCAR) strategy. The development was motivated by compositional and non-isothermal recovery methods, in particular miscible gas injection and in-situ combustion, and particularly suited to these applications. CCAR offers aggressive grid adaptation, which allows quick transition to the very fine local grids necessary to resolve solution fronts and the fine local grids desirable to resolve reservoir heterogeneity. CCAR is computationally efficient because of the underlying Cartesian topology, and requires minimal user intervention in the grid generation process. We use static refinement to generate a fixed base CCAR grid that accurately resolves the flow field, and propose a multi-level local-global upscaling strategy to determine appropriate permeability values for the CCAR grid. Dynamic refinement criteria are formulated to add adaptivity to the base grid where desired for accurate computation of transport. We also present a novel higher order pressure solver on the CCAR grids. The discretization uses a compact stencil, which together with an effective storage scheme leads to computational efficiency. The equations are solved with a parallel Algebraic Multigrid code.
Rheology and Transport in Porous Media of New Water Shutoff/Conformance Control Microgels
Authors: Rousseau D. , Chauveteau G. , Renard M. , Tabary R. , Zaitoun A. , Mallo P. , Braun O. , Omari A.
Published: December 2007

The performances of new microgels specifically designed for water shutoff and conformance control were extensively investigated at laboratory scale. These microgels are preformed, stable, fully water soluble, size controlled with a narrow size distribution, and non-toxic. They reduce water permeability by forming adsorbed layers soft enough to be very easily collapsed by oil-water capillary pressure, so that oil permeability is not significantly affected. Since the manufacturing process of these new microgels make possible to vary chemical composition, size and crosslink density, they can be designed as desired to meet the requirements of a given field application. The laboratory results reported in this paper concerns mainly three microgel samples having significantly different crosslink densities. We describe the relevant laboratory methods used to determine main microgel characteristics. The microgels have remarkable mechanical, chemical and thermal stability. Their behavior in porous media have been investigated extensively, showing that: 1) their propagation distance is only limited by the volume injected, 2) their injectivity is facilitated by a shear-thinning behavior and 3) water permeability reduction can be achieved as desired by controlling the thickness of adsorbed layer. Thus, this new microgels, now available at industrial scale, look as very promising tools, not only for water shutoff but also for conformance control in heterogeneous reservoirs.
Solution Error Models: A New Approach for Coarse Grid History Matching
Authors: O'Sullivan A. E. , Christie M. A.
Published: December 2007

This paper presents a new technique - solution error models - and applies it to the problem of history matching using simple coarse grid models. The solution error model technique is based on building a statistical model that describes the errors introduced in the simplified solution. The difference between observations and the coarse grid solution is measured by the "goodness of fit" (or misfit) term. The results show that a standard least squares approach to quantifying the misfit function yields significantly biased estimates of parameters, if the underlying model is biased. The bias can be almost completely corrected through use of the solution error model. The solution error model also introduces the use of time dependent covariance, instead of the usual single valued variance. This improves confidence in estimates of reservoir parameters.
An Extensible Architecture for Next Generation Scalable Parallel Reservoir Simulation
Authors: DeBaun D. , Byer T. , Childs P. , Chen J. , Saaf F. , Wells M. , Liu J. , Cao H. , Pianelo L. , Tilakraj V. , Crumpton P. , Walsh D. , Yardumian H. , Zorzynski R. , Lim K.-T. , Schrader M. , Zapata V. , Nolen J. , Tchelepi H.
Published: December 2007

We discuss an object-oriented, component-based architecture for a parallel reservoir simulator. The architecture successfully balances the need for extensibility, maintainability, and reuse with the need for efficient computation. Parallelism is hidden from the application developer via a set of abstractions and a unifying framework that supports static and dynamic load balancing on unstructured and structured grids. We explain how the simulator architecture supports black oil and compositional models within a general formulation, and how it achieves parallel scalability for all the major components: property calculation, Jacobian construction, linear solver, well model, input/output etc. Some initial results are discussed for a selection of models ranging from standard benchmarks to large complex field cases.

Motivation

Current generation reservoir simulators typically have a lifespan of at least 10 years. As a result, many of the simulators in widespread use have their roots in petroleum engineering, software engineering and computing technologies that were originally targeted at structured grids and scalar architectures. Advances in software and hardware technologies, parallel computing, advanced gridding and modern software engineering techniques have created new opportunities. At the same time, evolving workflows involving complex geological models, large full-field simulations, near well studies, production and facilities optimization, and stochastic modeling have placed new demands on reservoir simulation technology.

Although object-oriented design has been the main staple of software development for quite some time, its application to scientific programming has been hindered somewhat by the perceived inefficiency of run-time polymorphism. However, in recent years the emergence of compilers that are in full compliance with the C++ standard has made use of generic programming techniques commercially practical. Generic programming offers the benefits of encapsulation and code reuse without the overhead of virtual function calls1,2. Object- oriented and generic programming techniques using C++ have been shown to be useful in the development of scientific and numerical applications3,4.

Large-scale object-oriented frameworks for scientific computing have been developed in many contexts5, and parallelism has been addressed for example in the POOMA project6. Object-oriented architectures for flow simulations have been developed in other industries7 and these techniques have been applied to reservoir simulators by several practitioners within academia8,9,10,11,12 and also in industry13.
Sibling Rivalry: Competitive Tendering vs. Direct Selection - A Debate of Suitable Procurement Method on the Achievement of Supply Chain Objective in the Oil and Gas Operator Industry
Authors: Komala M. , Modana I. G. K. , Le Hello Y. , Naibaho S.
Published: December 2007

Competitive Tendering (read: Call-for-Tender) and Direct Selection (abbrv. DS) are kinds of procurement method that should provide oil and gas operator with sound quality service and materials (read: goods), timely deliverance, competitive price, and high service quality for the exploration, production, and health-safety-environment. In fact, both rarely go hand-inhand in contributing such objectives. That makes the "Sibling Rivalry" term is represented in this paper.

In this paper, the author uses a deductive analysis using pilot project of these methods by a major operator, benchmarking, and survey of the distribution network will show data as the impact on the application of particular method. The scope's limitation set along with parameter of Center for Advance and Purchasing Studies, research only on the upstream level of the industry, and the exclusion of specific regulation of a particular country. The conclusion of whether certain method more suitable for a particular situation would finally be presented.
Initial Souring Monitoring and Souring-Mitigation Testing Using an Online Souring-Mitigation Cabinet (SMC) Prior to Live Produced Water Reinjection (PWRI) and Nitrate-Based Souring-Mitigation Treatment on Norske Shell's Draugen Platform
Authors: Dinning A. J. , Oliphant D. , Vik E. A. , Bruås L.
Published: December 2007

The risk of reservoir souring is understood as one of the most serious effects of produced water reinjection (PWRI). Costly well backflows are traditionally used to monitor these effects. On Draugen (produced water 60°C, lean in carbon), a PWRI pilot is currently implementing nitrate to mitigate souring. Well backflows were not possible and another monitoring method for souring parameters was required. A souring mitigation cabinet (SMC) (two 1.4m columns with a 12 cm diameter, using a reservoir simulated sandstone medium), was designed. A side-stream of produced water was routed through the SMC over 3 months to allow typical reservoir biofilm development. Varying doses of nitrate (100, 80 and 50 mg per L) and nitrite (100mg per L) were then tested over a period of 15 days.

Stoichiometric inhibition of SRB souring by nitrate (80 mg per L) and removal of background sulphide (100 mg per L) was exhibited. Nitrite (100 mg per L) exhibited short term stoichiometric mitigation. Control sulphide varied between 5 and 9 mg per L. 80 to 85% utilisation of nitrate and nitrite was shown. Dissolved organic carbon consumption was 28 and 29%, indicating no exacerbated carbon consumption in the test column. A two log10 difference in mesophilic SRB (30°C) and thermophilic SRB (60°C) was exhibited between the columns. NRB did not vary.

The application of nitrate and nitrite stoichiometrically mitigated souring in the Draugen system and reduced the SRB population in the test column.

This demonstrates the use of a SMC with a biofilm of the same properties as that developing in the near well area during PWRI. Such studies may reduce the requirement of backflows and give the opportunity to repeat trials of different mitigation strategies during operation and independent of PWRI. The SMC is being maintained on Draugen and is currently used to control mitigation effects on bulk produced water during PWRI.
Exploration Well Testing With a Venturi/Dual Energy Gamma Ray Multiphase Flow Meter — A Case Study From Oman
Authors: Al Araimi N. M. , Jha N. K. , Al Zakwani S.
Published: December 2007

Throughout recent years, in exploration well testing, multiphase flow metering technology has offered an attractive alternative to conventional well testing equipment. To assess the benefits and limitations of multiphase flow metering technology in exploration well testing, a multiphase flowmeter was used in combination with conventional well test equipment on an onshore exploration well in Oman.

In exploration well testing, conventional equipment has to handle solids, slugs flows, well construction fluids (N2, HC1,…) and well effluents. These particularly challenging conditions affect the capacity of measuring accurately the produced and completion fluids. With the use of the multiphase flow meter, a more complete flow history was obtained through accurate clean up monitoring. Quantifying recovered completion fluids assisted in a timely decision about end of clean up period thus saving time, while a good match with expected recovery volume increased the confidence in acquired data.

This exploration well test was performed in a remote desert location with unpaved access roads. The well testing set-up using the multiphase flow meter had a smaller volume of equipment and the reduced weights and footprints led to savings in terms of mobilization and set up time.

This paper presents the multiphase well test equipment used for this exploration well test highlighting the advantages over conventional well test equipment. The various steps taken to validate the multiphase flow meter measurement with particular focus on the water cut measurement have been reviewed.
Optimizing Streamline Coverage for Efficiency and Accuracy
Authors: Matringe S. F. , Gerritsen M. G. , Mallison B. T.
Published: December 2007

The efficiency of streamline simulation, and in particular compositional streamline simulation, can be improved greatly if the streamline density is allowed to be locally adapted.A dense coverage is generally needed near composition fronts while in other areas of the flow domain a coarse streamline coverage may suffice to give accurate saturation and compositions. In the traditional streamline method,streamlines are viewed as fluid carriers. The associated low order mapping of compositions from the streamlines to the background grid used to solve for flow requires each background grid cell to be crossed by at least one streamline. This constraint prohibits local streamline adaptation and often leads to an unnecessarily high density of streamlines in large parts of the reservoir. For compositional problems, for which most of the computation time is spent on flash calculations along the streamlines, this approach leads to high and unnecessary costs. In such applications, it is crucial to minimize the number of streamlines, while ensuring a minimum streamline density to achieve the desired solution accuracy.

We view streamlines as forming a flow-based unstructured grid for transport. This viewpoint, together with an improved accurate mapping from streamline grid to background grid proposed by Mallison, Gerritsen and Matringe (2004)1 allows us to locally increase or decrease the streamline coverage. The new framework also allows partial streamlines (that do not start and end at wells) to be used to dynamically increase the local streamline density where necessary. To determine what streamline density is needed in different regions of the flow domain we designed an indicator that a priori detects areas of potential high mapping errors. The indicator takes into account the local density of streamlines as well as the proximity of solution fronts. This new streamline coverage control algorithm, combined with Adaptive Mesh Refinement (AMR) along the streamlines, can be viewed as an AMR strategy for the streamline grid.
Residual Oil Characterization for a California Turbidite
Authors: O'Brien C. P.
Published: December 2007

California's oil fields are rapidly maturing. Enhanced oil recovery may sustain the life of these fields. Residual oil saturation is one factor in determining the success of enhanced oil recovery projects. Miocene turbidite data from the giant Elk Hills Oil Field, California, illustrate a process to characterize laboratory residual oil saturation tests and approximate values in gravity drainage and waterflooding processes. This characterization will aid in assessing the potential of enhanced oil recovery in California's mature oil fields.