bluuebunny/crossref_metadata_2025 huggingface dataset:
Possibilities for Reduction of Emissions—in Particular the Greenhouse Gases CO2 and CH4—in the Oil and Gas Industry
Authors: Müssig Siegfried
Published: December 2007

Stock-taking of CO2 and CH4 emissions from the energy sources natural gas and crude oil from origin to final use having been established, possibilities for reducing these greenhouse gases have been evaluated.

Combined cycle processes, heat pumps, fuel cells, etc. have been studied as measures to increase the efficiency of combustion processes. The use of CO2-free energy sources as well as the logistics and the disposal of CO2 in depleted reservoirs or in the oceans have been considered.

The introduction of hydrogen as an additive to natural gas has been considered.

The possibilities of reduction of methane emissions are demonstrated for high-pressure gas transmission lines, dehydration units and low-pressure flowlines including burners. The possibilities of reduction of NOx, CO and UHC emissions in domestic and industrial use are also shown.

It is shown that all processes considered increase combustion efficiency and also offer possibilities for reductions in emissions of greenhouse gases. Fuel cells also indicate a high potential for the future. Special techniques which are currently being introduced in the gas and oil industry are also effective in reducing NOx and CO emissions from combustion engines and burners.

Solar energy, power generation by wind force and other CO2-free energy sources are not recommended for the gas and oil industry; this is left to public power generation. The disposal of CO2 in depleted reservoirs or oceans appears possible, but this is neither an effective method nor an easy to handle procedure.

Reduction in methane emission is relatively easy to achieve.

The developed concepts for the reduction in emission of greenhouse gases and other pollutants can be applied in all sectors of the gas and oil industry. They are regarded as technically sound. An improvement in the economics of these measures is still desirable.
Quality Assurance/Quality Control for the Sake of Hole Safety
Authors: Parigot Philippe
Published: December 2007

PERSONNEL, RIG EQUIPMENT and ENVIRONMENTAL safety are topics responsibly addressed today by all Companies involved in the oil industry. A strong and common commitment leads to a continuous improvement which is supported by a costly effort in research and reinforced by detailed procedures and regulations. On the other hand, HOLE safety seems to have been given a lower priority. A general consensus that makes a fully comprehensive effort in this domain and that accepts to pay the corresponding cost, does not seem to exist.

Driller's procedures are firmly described and strictly respected. Mud Logger, Mud Engineer, etc… must accept the same constraints supported by thorough QA/QC on the corresponding procedures.

This paper presents a variety of true field cases which highlight the missing link in the general safety concept.
The Innes Field: Complete History of a Marginal Subsea Development
Authors: Harries P. G. , Smith Christopher , Compton S. E.
Published: December 2007

The Innes field, lying in Block 30/24 of the UK North Sea was discovered in 1983. After a single appraisal well had been drilled and an extended production test on the initial discovery well, estimated reserves were uncertain but low. Economic development of the field was achieved in two phases, using low cost proven technology in an innovative manner. The first phase involved the use of a floating production facility. In the second phase the economic field life was extended by the tieback and production of the Innes field as a remote subsea satellite, 14 km from the floating production facilities at the Argyll Field. The Innes field produced in this mode until cessation of production in December 1990.

Material balance modelling confirms the drive mechanism as solution gas drive, supported by minimal aquifer influx, with the migration of mobile gas to form a secondary gas cap. Total recovery by the end of field life has been 5.8 MMSTB, equating to a recovery factor of approximately 30 %.
Multiphase Flow: A Cost-Efficient Solution for Marginal Field Developments
Authors: Falcimaigne J. R.
Published: December 2007

Satellite developments are an attractive solution for producing oil from small marginal fields. However, their application is limited by the distance that the crude oil can travel with the natural pressure of the reservoir. To overcome this limitation the paper proposes to use multiphase pumping to provide energy to the fluid. To implement this technology at low technical risks, the pumping unit could be located at the surface, aboard a small floating support. The production would be exported by means of a reusable flexible pipe to a processing centre.

After presenting recent advances in multiphase production, the paper describes the proposed system, designed to produce fields with 20 to 60 millions bbl. of recoverable reserves and located from 10 to 60 km, or beyond, from existing facilities or the shore. The system is characterized by its mobility. After depletion of a Held, it can be easily retrieved and moved to another location. In addition to reduced capital expenditures and relocability, the proposed system may accelerate the oil recovery of a field and the produced gas can be processed on the host platform and exported in an existing pipeline system.
Development and Standardisation: Challenge or Contradiction?
Authors: Sandhaugen R. A. , Lindland H. J.
Published: December 2007

This paper reviews Statoil's experience with standardisation of its subsea field developments. Aspects of maintaining standard specifications in a rapidly developing technology are discussed, as well as the inherent disadvantages and advantages of this approach. Subsea standardisation applied at correct system design level and agreed with potential suppliers, will contribute to economical development of marginal fields.
Remobilisation of Trapped Hydrocarbons in Water-Invaded Zones of Gas Condensate Reservoirs
Authors: Henderson G. D. , Danesh Ali , Tehrani D. H. , Peden J. M.
Published: December 2007

During the production of gas condensate reservoirs which have underlying aquifers present, large areas of the reservoir can be invaded by water during pressure reduction, resulting in the entrapment of large quantities of hydrocarbons. In order to simulate this process in the laboratory, experiments were conducted using gas and condensate saturated cores which were initially flooded with water to simulate the entrapment of hydrocarbons. Pressure reduction of the cores was then initiated in order to allow the hydrocarbons to expand and reach a critical hydrocarbon saturation at which hydrocarbons remobilised.

It was found that the average critical hydrocarbon saturation required for remobilisation of hydrocarbons was approximately 0.56, which was about 0.12 higher than the initial hydrocarbon saturation. Pressure reduction was initiated at different stages in the phase behaviour of the gas condensate fluid in the cores. This appeared to have only a minor effect on the hydrocarbon expansion required for remobilisation when the initial hydrocarbon saturations were similar. The results highlighted significant differences between the hydrocarbon expansion required for remobilisation, the fluid production profiles after remobilisation, and the effect of pressure reduction rate on remobilisation, for the gas condensate compared to a single phase gas.
How to Rate Crude Oils for Alkaline Flooding Potential: A Study Based on 239 Crude Oils
Authors: Smith J. E.
Published: December 2007

This paper presents an overview of results of 239 crude oils which have been tested over a 10-yaar period. The oils represent 83 different formations. Analysis data from the Department of Energy (DOE) was available for 103 of the oils. Alkaline reactivity was correlated with crude oil composition and properties. Oils that contained a high proportion of vacuum distillate and components that tend to concentrate in the vacuum distillate had a high probability of alkaline reactivity. High molecular weight aromatics positively influenced alkaline reactivity, while paraffinic components had the opposite effect. Chemical properties correlated with alkaline reactivity more strongly than physical properties. A rating system based on factors that influence reactivity was constructed and applied to groups of oils. The rating system should be used as an initial screening tool for alkaline flooding potential.
A Review of Retention Mechanisms of Ethoxylated Sulfonates in Reservoir Cores
Authors: Austad Tor
Published: December 2007

The present paper reviews work done on the adsorption of ethoxylated sulfonates during the Norwegian state-supported program on IOR, termed SPOR.The objective of the project is to obtain fundamental understanding of the mechanisms involved concerning the loss of surfactants by chemical flooding of sandstone reservoirs in The North Sea. Special emphasis is made concerning the effects of clay minerals in reservoir cores.The first part deals shortly with ethoxylated surfactants in general, chemical analysis, chemical stability, and temperature and salt tolerance. Both static adsorption onto model core material and nonequilibrium dynamic adsorption in reservoir cores, chromatographic effects, and possible sacrificial agents are handled in greater detail.
Growth and Control of Sulfidogenic Bacteria in a Laboratory Model Seawater Flood Thermal Gradient
Authors: Salanitro J. P. , Williams M. P. , Langston G. C.
Published: December 2007

A model laboratory oilfield reservoir system consisting of a packed sand thermal gradient under continuous seawater infiltration was constructed to study the migration, persistence and activity of sulfate-reducing bacteria (SRB). Nutrients (fatty acids and NH4+/PO4−3) or biocide (glutaraldehyde) were added to the injection water to determine optimum conditions for SRB growth and control of microbial H2S formation. Halotolerant SRB isolated from Gulf Coast seawater were injected into the packed sand to promote colonization. Data obtained from several experiments demonstrated that: 1) there is no apparent correlation between the numbers of viable SRB recovered in a waterflood and the presence of H2S levels, 2) SRB which grow optimally at 25 and 35°C are thermo-tolerant and could be recovered from higher temperatures of the gradient (55 and 75°C). 3)Microbial sulfide production in the seawater and formation water injection fluid occurred only when lactic acid substrate was present, 4)H2S levels generated in the packed sand varied from 50–150 mg/day (30–100 mg/1 column effluent), 5) SRB growth and activity in the seawater flood could be significantly eliminated by the addition of high biocide concentrations (> 1000 mg/1 glutaraldehyde) and 6) SRB produced H2S that was depleted in δ34S from the seawater SO4−2 by 10–12 per mil (δ34S = +6 to +8). These results show that sulfidogenic bacteria injected into a reservoir with the flood water may survive higher temperatures in the formation and be recovered from producing well fluids. These organisms may colonize cooler zones and sustain growth by degrading fatty acids in formation waters. Furthermore, recent literature findings on the isolation of extremely thermophilic fatty acid-utilizing sulfate-reducers (grow at 70–90°C) and SRB capable of growing on saturated hydrocarbons (C12 – C16) from oilfield production systems and anaerobic sediments suggests that thermophilic oil degraders may also be responsible for the onset of sour gas production in initially sweet waterfloods.
Crosslinked Borate HPG Equilibria and Rheological Characterization
Authors: Kesavan Subramanian , Prud’homme R. K. , Parris M. D.
Published: December 2007

Viscoelastic properties of hydroxypropyl guar (HPG) crosslinked by borate ions were studied using steady shear and dynamic oscillatory shear experiments. Chemical equilibria involving boric acid, borate ions, and borate ions associated with cis-diol sites on the polysaccharide chains determine the number of crosslinks. These equilibria are functions of temperature and pH, and thus the rheology of the borate gels depend on temperature and pH. Dynamic oscillatory measurements on polymer solutions crosslinked by borax were performed over the temperature range from 10°C to 65°C, and the pH range from 6.35 to 9.5. The storage and loss moduli obey time-temperature superposition so that master curves can be constructed over 6 decades in frequency. Leibler, et al. have recently proposed a theory for the rheology of associating polymer systems. Following this theory, we have subtracted the solution moduli from the gel moduli and the resulting reduced moduli data follow a single time constant Maxwell model. Steady shear experiments were performed in capillary tubes at two different diameters to determine wall slip. The shear rates studied were such that the chains do not have sufficient time to relax completely. By analysing the data from the two tubes, the gel was found to slip at the wall. Three different regions were seen in the stress – shear rate behavior of these gels. At low rates, the stress increases rapidly with shear rate. At intermediate shear rates, the stress remains constant and at high shear rates, the stress increases slowly with rate and the gel is found to slip in this region. The actual stress – shear rate behavior after accounting for slip and slip velocities were determined.
Experimental Validation of Sandstone Acidization Models
Authors: Hsi C. D. , Bryant S. L. , Neira R. D.
Published: December 2007

Sandstone HCl/HF acid matrix stimulation is a complex process involving numerous minerals and reactions. Previous attempts to model these reactions employed a "lumping" procedure to classify sandstone minerals as either fast reacting or slow reacting depending on their reaction rates with hydrofluoric acid.

Bryant (1991)1 showed that the two-mineral dissolution model can not accurately account for the effect of flow velocity on HF consumption rates. Consequently, this model cannot reliably extrapolate laboratory data to field conditions which involve radial flow geometry. Bryant presented an improved model to include the secondary dissolution/precipitation reaction of fluosilicic acid (H2SiF6) with clays and amorphous silica. The improved model was previously tested only against limited published data from three laboratory acid core flood tests. To further validate the model, additional laboratory acid core flood tests were conducted using different sandstone cores and with different acid injection rates and concentrations. Test results show that the improved model not only predicts the HF effluent histories reasonably well but also predicts the dissolved Si and Al concentration profiles in the effluent acid. This suggests that the improved model provides a more reliable basis for extrapolating laboratory data and for simulating matrix acid treatments. The improved model also helps to understand the dissolution/precipitation reactions occurring during sandstone acidization processes.
Compositional Reservoir Simulation With a Predictive Model for Viscous Fingering
Authors: Rubin Barry , Barker J. W. , Blunt M. J. , Christie M. A. , Culverwell I. D. , Mansfield Mark
Published: December 2007

This paper describes how an empirical model of compositional viscous fingering can be implemented in a conventional compositional reservoir simulator without major changes to the code. The empirical model is used to calculate pseudo relative permeabilities, transport coefficients (‘α-factors’) and a new density coefficient (‘β-factor’) which are used as input to the modified simulator. The modified simulator predicts the average behaviour of a variety of unstable gas displacement processes. The results are shown to be in excellent agreement with those of conventional compositional simulations which resolve the fingering explicitly.
Scaling Up the Non-Newtonian Flow Characteristics of Polymers, Foams, and Emulsions
Authors: Coombe D. A. , Oballa Viera , Buchanan W. L.
Published: December 2007

A generalized compositional thermal simulator is used to analyze the impact of the non-Newtonian flow characteristics of polymers, foams, and emulsions at three length/time scales.

At the pore scale a novel use of a reservoir simulator is employed to create networks of varying topology in order to study the impact of porous media structure on rheological behavior. Aspects of non-Newtonian flow of polymers, foams, and emulsions at this scale are then compared and contrasted. In particular the suitability of viscometer power law parameters to porous media, and the role of pore constrictions in trapping and mobilization are considered.

Subsequently, the non-Newtonian behavior of these fluids at the core and field scales are examined. It is shown that the impact of heterogeneity, crossflow and radial flow patterns, and region dependent trapping have analogies with the more microscopic scale. Furthermore, the shear rate dependence of in situ foam and emulsion generation suggests different modelling approaches at the core and field scales, with core scale rate processes replaced by pseudo-equilibrium K values at the field scale.

Numerical aspects of non-Newtonian modelling (explicit versus implicit and block-centered versus face-centered velocity evaluation) are discussed briefly.
A New Limited Compositional Reservoir Simulator
Authors: Tang D. E. , Zick A. A.
Published: December 2007

A new, limited compositional reservoir simulator has been developed. The development of this simulator was motivated by the fact that there are fundamental flaws in the formulation of existing four-component simulators. The unique feature of this simulator is that its phase behavior model is based on the concepts of pseudoternary, equilibrium phase diagrams. Phase envelopes are composed of pressure-dependent, piecewise linear bubble-point and dew-point surfaces with tie lines provided by a generalized version of Hand's Rule. Equilibrium calculations are noniterative and very efficient. Densities and viscosities are modeled by an equation of state and the Lohrenz-Bray-Clark correlation. This new model captures the essential physics missing in conventional four-component simulators.

Other features of the simulator include the Todd-Longstaff mixing model and compositionally consistent relative permeabilities. A practical example application of this new simulator is provided.
A More Accurate Numerical Scheme for Locally Refined Meshes in Heterogeneous Reservoirs
Authors: Hermitte Thierry , Guerillot D. R.
Published: December 2007

During reservoir simulation, the process of inferring the behavior of a real reservoir from the performance of a mathematical model implies a coarse discretization of the region to be simulated. The use of large size grids (blocks of several hundred of meters) increase numerical dispersion, therefore masking the physical phenomena actually occuring. The simulation then does not take into account wellbore effects, fluid fronts, etc. In that case, results are not accurate and thus unreliable. Reduction of the grid block size improves results accuracy but increases the number of blocks. Running costs become then too high. In order to decrease the grid block sizes without significantly increasing their number, Adaptive Mesh Refinement Method can be succesfully applied whereby the grid is locally refined when certain physical phenomena are expected to occur and need a better precision at the local level.

For such a method to be succesful, a dynamic data structure is needed as well as a higher order numerical scheme for pressure and saturation. The main difficulties are to approximate the fluid fluxes at the interface of two blocks belonging to two regions having been refined differently. Indeed, in this situation the block nodes are not aligned anymore, thus requiring a higher order approximation. The problem is then to obtain a numerical scheme having excellent theoretical properties such as conservativity and convergence.

This paper presents a new numerical scheme (conservative and convergent) with a good accuracy through use of locally refined grids. Furthermore, this new Scheme for Local Refinement Technics, SLRT, takes into account reservoir heterogeneity.

A comparison was made between this new scheme (SLRT) and other schemes suited for locally refined grids both for homogeneous and heterogeneous media. We show that this new scheme gives a better approximation for pressure and saturation. It can be easily implemented on any available simulator.
Extension of the TVD Midpoint Scheme to Higher-Order Accuracy in Time
Authors: Rubin Barry , Edwards Michael
Published: December 2007

A new approach for increasing the space and time accuracy of numerical schemes employed in standard (commercial) reservoir simulators is presented in this paper.

We introduce a novel TVD fully second order flux approximation (Two Time Level Flux TTLF) extending the work previously done on applying TVD schemes [1] to general purpose Black Oil/EOS Compositional reservoir simulators (eg. VIP). The TVD TTLF scheme is a more fundamental application of flux limiters on the second order Taylor's series expansion of the inter-block flux. This enables commercial first order accurate simulators to achieve second order accuracy in both space and time without significantly increasing their complexity.

This paper presents the development of the improved temporal accuracy TVD scheme and the results of the scheme on linear and non-linear 1-D pulse propagation problems and 2-D finely gridded compositional problems.
A Fully Explicit Scheme in Reservoir Simulation on a Massively Parallel Computer
Authors: Piault Emmanuel , Ding Yu
Published: December 2007

A new approach to solving the equations governing oil reservoir simulation is described. The generalization of an explicit unconditionally stable scheme for the heat equation is presented. This sclreme is used to solve the pressure equation of a diphasic model. Massively parallel computer, which have shown their capacity in high speed computations for explicit finite difference scheme, is used.
TOPEX: An Expert System for Estimating and Analyzing the Operating Costs of Oil and Gas Production Facilities
Authors: Greffioz Jean , Olver A. J. , Schirmer Patrice
Published: December 2007

TOPEX is a new approach to operating cost estimation of oil and gas installations. It does not rely on knowledge of the capital cost of the installation and uses a computerized expert system (or knowledge base).

Estimates are generated from specific details of the equipment and systems and general databases of prices and manhours.

A novel methodology has been developed for quantifying the operational complexity of an installation which is then correlated with operations manpower.

The use of a computerized application allows rapid calculation of estimates so that what-if and sensitivity studies can be readily done.

The knowledge base provides a powerful tool to handle the large amounts of data involved and acts as a repository for the expertise used in its development.
A Cheap Method for the Load-Out and Installation of Tambora Central Production Unit
Authors: Poirier D. J. M. , Accart M. A.
Published: December 2007

TAMBORA and TUNU gas fields are located in the delta of the Mahakam river in the province of East Kalimantan (Indonesia) in the vicinity of HANDIL and BEKAPAI oil fields currently operated by TOTAL INDONESIE, (fig. 1)

In 1988, TOTAL INDONESIE launched the initial phase of development of these two fields enabling the production of 300 MMSCFD of gas by end of the year 1990.

The new facilities installed at this time included a single level platform of 2,600 m tons weight (TAMBORA Central Production unit no. 1).

In order to minimize the construction cost, the platform was installed by ballasting in one single piece without using cranes for lifting parts of the structure into place.

Due to the nature of the structure of the platform, the construction involved three delicate operations requiring special care:

the pre-driving of 16 piles which required accurate positioning. the load-out of the deck with its possible harmful effect on the integrity of the structure. the installation of the deck to be performed within a limited period of time (tide window).

The operation was successfully achieved and the method proved to be workable, safe and economical.
Slim-Hole Drilling in the Gulf of Suez, Egypt
Authors: Ghazaly S. M. , Khalaf Fouad
Published: December 2007

This paper discusses the economical, operational and environmental aspects of the reduced hole size drilling now used in offshore operations in Gupco and other major petroleum companies operating in the Gulf of Suez Area Egypt. The results demonstrate that reduced hole size drilling saves cost: use of slim hole reduces time related intangible savings, fixed tangible savings, and tangible equipment savings.

The advantages of smaller hole size and the reduction in the volume and size of oil wet drilling cuttings help minimize the environmental impact associated with the use of oil base mud. The reduction in drilling fluid volume and treatment cost, higher rates of penetration, better hole cleaning capabilities, savings in consumables (such as bits, mud, cement and diesel oil), less tangible cost, and easier equipment mobilization are interacted to produce significant operational gains. This results in savings of 40 to 50 percent of well costs versus the cost of conventional wells drilled in the same area.

Although substantial saving were realized, there are elevated risks with the major one being the lack of a good contingency in the event unexpec-ted hole condition or geological condition require an extra casing to be run prior to reaching the total depth. Drilling 6″ hole size (or less) for long sections is difficult. Usually, very slow drilling R0P is associated with erratic directional responses, and can restrict use of MWD tools. Moreover, more drill string failures are likely to occur.

Effective preplanning between the drilling, exploration, and engineering to accurately define possible geologic targets and their potential drilling problems can minimize these risks associated with drilling slim holes and provide higher levels of success in meeting objectives.

In summary, slim hole drilling offers significant operational and environ-mental advantages. And cost savings relative to the conventional well design were realized in the Gulf of Suez – Egypt.
Factors Limiting the Quantitative Use of Mud-Logging Data
Authors: Kyllingstad Åge , Horpestad Jan L. , Klakegg Sigve , Kristiansen Ansgar , Aadnøy Bernt S.
Published: December 2007

This paper focuses on the quality of mud logging data and the need for improving the quality. Included examples clearly demonstrate that traditional mud logging data suffers from errors and poor quality which limits its quantitative use, for instance in drill bit optimisation or modelling work. Special concern is paid to the accuracy of the depth, the rate of penetration and the surface weight on bit. It is concluded that there is a significant potential for improving the accuracy of these variables.
The Upstream Oil and Gas Industry's Initiative in the Development of International Standards
Authors: Thomas G. A. N. , Thorp Geoffrey
Published: December 2007

The paper describes the international work of the oil industry to formalise as International Standards many of the industry standards used world-wide. It also describes how matters have been developing in Europe.

E&P Forum, representing the international exploration and production oil and gas industry, provides a forum for co-ordinating industry standardisation, to ensure that the necessary standards are maintained by the appropriate technical body.

The paper discusses the development of the standardisation programme in ISO/TC67, the Technical Committee directing the transformation of some 70 API Standards into ISO Standards and the relationship to CEN (the European standardisation body).

The objective of the upstream industry is to operate world-wide to consistent international standards. Company standards can then concentrate on functional and performance requirements. This will facilitate international trade and communication, open competition and the global market. For a practical realisation of this objective the oil industry must foster a special relationship between the relevant US bodies, ISO and CEN. The sustained support of all sides of industry is required.
Standardisation of Tubular Goods – For Worldwide Application
Authors: Jones W. T. , Dharma N.
Published: December 2007

For many years the American Petroleum Institute (API) has provided base standards for the oil industry.

Over the past five years, the Oil Industry International Exploration & production Forum (E&P Forum) has worked closely with API, and the International Standards Organisation (ISO). Their goal has been to update Oil Industry standards for worldwide application.

The updating of Standards is required to assist in the harmonisation process which is necessary to meet the worldwide needs of the industry.

The paper will concentrate on the worldwide technical requirements for Tubular Goods, i.e. Casing, Tubing, Drillpipe and Linepipe.

The harsh environmental and climatic conditions of the North Sea reflect one geographic perspective. The established Tubular Goods Standards were originally developed within the USA and such harsh conditions were not envisaged. To address this, the Forum Work Group raised several technical issues initially with API, and more recently with ISO.

A number of technical issues are discussed, including the following:

Fracture toughness Ovality/outside diameter Gas tightness (Premium Connections etc) Use of PSL's

The paper will comment on the recent updates to API 5CT, and the more accelerated progress on the ISO Casing & Tubing Standard plus its potential adoption by CEN.

Linepipe Standardisation has advanced with the publication of the new CEN standard EN 10208 which will be covered at the end of this paper.
Optimal Perforation Design for Horizontal Wells in Reservoirs With Boundaries
Authors: Marett B. P. , Landman M. J.
Published: December 2007

Wellbore production rates can be significantly influenced by the frictional pressure drop in long inclined or horizontal wells, particularly in high permeability reservoirs with small pressure drawdown. In this paper, a steady-state model is presented which couples the Darcy flow into perforations from the reservoir with the frictional flow in the wellbore.

Reservoir-perforation behaviour is modelled by flow into discrete well perforations within a homogeneous, anisotropic reservoir bounded by infinite parallel planes. By considering the flow into individual perforations, the importance of adjacent boundaries, well inclination, perforation density, perforation phasing and crushed zone damage can be studied. Wellbore flow, specified as either single or multiphase, accounts for the pressure drop along the wellbore due to well inclination, pipe friction and perforation inflow.

To enable flexible wellbore design, the well is partitioned into segments each with its own inclination, length, and number of perforations. Perforation distributions can be user-defined or optimized through various optimization strategies; for example, maximization of wellrate, or uniformity of specific inflow. The model described in the paper has been implemented in software and is currently being used as a design tool.
Testing of the Oseberg Gamma North Horizontal Well
Authors: Søgnesand Sigmund
Published: December 2007

This paper describes the testing and production of the Gamma North horizontal well in the Oseberg Area. The 753 m long horizontal well section is located 11 ± 1 m above the oil-water contact in a 26.5 m thick oil zone with overlying gas cap. The Gamma North well is primarily a gas producer with a subsea completion tied into the Oseberg C platform. The reservoir development plan involves optimization of the oil recovery prior to the period of gas production from the gas cap.

Drilling of the well did not result in any major problems, and the horizontal section was drilled within 7 days. A prepacked screen is used to avoid sand production. Gas and water breakthroughs occurred a few months after production startup.

The Gamma North well was tested as a part of the initial completion program. The test sequence comprised of a cleanup flow, a stabilization period, and a shut-in period. The buildup data shows that no unique interpretation can be obtained. The analysis is based on reduction of variables, and the calculated parameters are in agreement with the geological well model.
Effective Fracture Stimulation in High-Permeability Formations
Authors: Elphick J. J. , Marcinew R. P. , Brady Barry
Published: December 2007

The application of fracturing to high permeability formations is presented.

The economic rationale for fracturing high permeability formations is different from conventional fracturing. The principal reasons for fracturing these formations are reviewed. Design and execution methods for these fracture treatments are presented where they differ from conventional fracturing.

High permeability formations often have a tendency to produce sand. The effect of fracturing on the sanding tendency and the potential of using fractures as a sand control method are discussed.
Bigbore Well Completions: A New Completions Technique for Arun Field
Authors: Cannan W. L. , McKenna D. L. , Sukup R. A. , Calvert D. G. , Quitzau R. , Sardjono S. , Ellison P. C.
Published: December 2007

The prolific Arun Field in North Sumatra, Indonesia continues to produce substantial amounts of natural gas and condensate. However, the massive carbonate reef reservoir is beginning to require special measures for more complete exploitation and recovery of the large quantities of hydrocarbon remaining in the formation. Optimization of production requires combined efforts from Arun geologists, reservoir, production, drilling, and operations personnel as well as technical advisors.

Although the Arun Field wells typically produce 30 to 100 MMSCFD per well, increased production rates are being achieved by utilizing larger bore wells and modifying the drilling and completion techniques accordingly. Substantial increases in gas and condensate production rates are being realized with a savings in investment over previous Arun Field drilling and completion methods utilizing conventional 7″ completions.

Previous completion techniques utilized 7" production tubing with either cased or open hole completions. The "Big Bore" completion technique has 9-5/8″ production tubing with an open hole completion to maximize deliverability. The primary purpose of the technique is to boost field productivity in order to meet gas demand, enhance condensate optimization, and allow flexibility in operations. This new completion technique required extensive equipment design and testing to meet anticipated production and stimulation conditions. This is the first time a completion of this type has been utilized in Indonesia, and as far as we know, these are the largest bore, gas producing well completions in the world. This paper discusses the performance of the wells and the various components utilized in this new "Big Bore" completion technique.
Processing Of Geological And Engineering Data Multipay Fields For Evaluation
Authors: Bankhead Charles C.
Published: December 2007

Introduction

Recent oil and gas property trade involving multi-reservoir fields have required that studies be made within stringent time limitations. The evaluation of these fields has necessitated the evolving of a streamlined method of gathering, cataloguing, processing, and interpreting the basic geologic and engineering data. Methods are herein outlined for the rapid processing of such data and for the preparation of structure and thickness maps suitable for the engineer's use in estimating reserves, in predicting reservoir performance, in determining development of the field for optimum primary and secondary recoveries, and establishing the bases for optimum future operating methods.

TIME AND BUDGET SCHEDULE

Before a study is undertaken, the geologist is often required to submit a budget estimate and a provisional time schedule covering the geological part of a reservoir study.

CATALOGUING AND CHECKING

The geologist's role in expediting the engineer's work in evaluating a single or multipay field starts immediately with the arrival of all of the client's available information. The mass of data received from the client must be checked in and catalogued. This is generally handled by a secretary-technician, referred to in this paper as a statistician. The geologist aids in segregating material which can be transmitted immediately to the engineers and that which is essential or useful for preparing the necessary geological maps for the engineer's use. The material is then checked against a gathering data list comprised of most of the items listed below, and any missing items are ordered.

DATA ROUTING

Engineers: The engineers are generally given the following items immediately:Copy of the schedule of lease and wells.A preliminary work copy of a well and lease location map.Schedule of income and expense interests.Schedule of oil and gas prices and trucking charges.Schedule of operating expenses and ad valoremtaxes.Core descriptions, copy of core data, and special core analysis reports.Fluid data including fluid sample analyses, surface fluid sample data, GPM tests, gas analyses, and water analyses.Production data-oil, water, and gas by leases and/or wells by months.Special well tests on oil wells, deliverability tests on gas wells, GOR and watercut tests.History of reservoir performance including data and curves of BHP, GOR, and rates vs. cumulative production.Any engineering committee reports, reports on reservoir studies, outside consultant reports, and MER data.

All the foregoing data will permit the engineers to start their tabulations and studies simultaneously with the geological section.

Geologists:The geological basic data generally includes the following:Schedule of leases and wells.Maps and location plots, including client'sstructure and isopach maps.Client's cross sections and regional data.Logs (electrical, sonic, induction, micro, gammaray-neutron) and completion cards.Well completion data, including DST data, mechanical data, and other significant well file data.
Field Optimization of Steam/Foam for Profile Control: Midway-Sunset 26C
Authors: Gauglitz P. A. , Smith M. E. , Holtzclaw M. I. , Duran H.
Published: December 2007

Chevron conducted a steam-foam trial in Midway-Sunset 26C to optimize the use of steam-foam, without the addition of a non-condensible gas, for improving profile control in a steam injection well. The field experiments were designed to find the optimal surfactant concentration and liquid volume fraction (LVF), or steam quality, for improving injection profiles with steam-foam. The effect of the total steam injection rate on the ability to generate a foam was also determined by using three chokes of different size. In all these tests, nitrogen was not added, because the goal was to develop a low-cost foam process. We also collected new laboratory data to determine the ability of low concentration foams to divert flow from higher to lower permeability sands.

Radioactive tracer measurements gave injection profiles with foam injection under ten different conditions, and five profiles were measured without foam injection. Downhole pressures were measured during these tests and under other conditions. Results show that increasing the steam LVF by blending water with the steam dilutes the surfactant, but improves foam generation and gives better profile improvement. Steam-foam improved the injection profile for concentrations greater than about 0.1 weight percent (wt.%) Chaser™ SD1020 at a steam LVF of 0.02 for the well tested. For surfactant concentrations below about 0.1 wt.%, the injection profile was changed but not improved. Tests showed that increasing the total steam injection rate from 180 to 630 BPD-CWE gave a larger pressure response due to foam for a range of surfactant concentrations. The test showed that profile improvement can be achieved with surfactant injected at about half the rate that was previously shown as necessary for in-depth foam applications, and this was accomplished without the addition of nitrogen.
The Effect of Steam/Foam Injection in a Steamfiood Experiencing Downdip Steam Migration
Authors: Bautista L. S. , Waninger E. A.
Published: December 2007

A one pattern steam foam field trial was conducted in the Amnicola sand in the steamfiood of Section 26W, Cymric Field. The pattern was located in an area in which downdip steam migration occurred, soon after steam injection began, as a result of well spacing (which skewed injectors closer to downdip producers) and channeling (due to vertical permeability stratification).

The primary objective of the trial was to economically minimize the downdip steam migration, and consequently improve the sweep efficiency of the steamfiood. Chevron Chaser™ SD1020 was continuously injected with steam and nitrogen for approximately seven months. Reservoir conditions and production were monitored and analyzed to determine the effectiveness of steam foam as a mobility control agent.

The field trial also identified non-foam alternatives effective in reducing downdip steam migration. Operating strategies employed in the steamfiood to accelerate early oil production were analyzed to understand their effect on the reservoir, given skewed well spacing and vertical permeability variation.
The In-Situ Formation of Bitumen-Water-Stable Emulsions in Porous Media During Thermal Stimulation
Authors: Bennion D. B. , Chan M. Y. S. , Sarioglu Gurk , Courtnage Dave , Wansleeben John , Hirata Toshiyuki
Published: December 2007

The formation, production and handling of highly viscous bitumen-water emulsions is a significant problem in the operation of many heavy oil thermal stimulation projects. This paper documents an extensive study examining the in-situ emulsification of bitumen and water under conditions of simultaneous flow In an unconsolidated preserved state porous media at full reservoir pressure conditions and at a temperature of 200° C. Various co-injection ratios from 100% bitumen - 0% water to 100% water and 0% bitumen were examined in both water saturation increasing and decreasing directions (drainage and imbibition). The test results indicate that in-situ emulsification does occur, that certain simultaneous flow ratios cause a localized increase in the severity of emulsification, and that the degree of emulsification appears to be related to the relative flowing proportion of fluids inside the porous media. Some evidence of directional hysteresis effects on emulsion quality were also observed.
Comparison Between Political and Economic Country Risk Factors
Authors: Proehl T. S.
Published: December 2007

Political risk analysis, or country risk analysis is one of the more contentious topics in the petroleum economics universe. Overseas investors have several choices with regard to country risk analysis. Ignore itDelegate analysis to outside expertsCalculate it themselves

In the real world, investors would probably choose to avail themselves of outside counsel AND calculate risk factors themselves, provided a suitable method to do so exists. Ideally, the process of consulting experts and performing internal assessment of potential risks facing an investment proposal would produce chance factors for various scenarios which could be utilized in expected-net-present-value calculations.

Economic investments always occur in a political environment Economically sensible projects should encounter political acceptance. Foreign investment projects ultimately must make economic sense to host nation governments and their populations, as well as to investors. Political risks tend to materialize whenever large, organized groups within a host nation perceive foreign investment as something which ceases to make economic sense to them. More specifically, whenever people perceive foreign investment as being detrimental or neutral toward their economic interests, the potential for political risk events increases.
Future Oil Production in the North Sea
Authors: Takin Manouchehr
Published: December 2007

The North Sea is generally considered a high cost oil province; thus the price of oil and the cost of production are the two key parameters which will control its future production profile. A detailed study was carried out on more than sixty new fields in the Norwegian and the UK sectors. For each field, the investment intensity (Dollars per daily barrel) and the fully-built-up lifetime unit cost of production were estimated. The results cover a wide range but reach more than $30,000 per daily barrel for the investment intensity and more than $30 per barrel for the unit production cost. By comparing the costs with future oil price scenarios, it is estimated that the level of oil production in the North Sea could be between 3.6 and 5 million barrels per day in 1995 and between 1.6 and 2.9 million barrels per day in the year 2000. These production estimates include the incremental production from the new fields and the contribution from the existing fields. It is interesting to note that some high cost fields are undergoing development although the present outlook for oil prices may not justify their development. This may suggest three possible reasons: the companies investing in these fields anticipate higher future oil prices, they put a considerable emphasis on supply security and political stability in the North Sea, or they are hoping to achieve significant reduction in costs.
The Value of a Seismic Option
Authors: Stibolt R. D. , Lehman John
Published: December 2007

Exploration and production agreements worldwide typically include seismic surveys and exploratory drilling obligations as key contractual provisions. In some jurisdictions, most notably the United States, agreements typically do not include drilling obligations. The lessee holds a right rather than an obligation to drill and, therefore, may relinquish acreage without drilling if the results of seismic surveys or other geological tests prove unfavorable. It is often possible in other jurisdictions to negotiate such a "seismic option" in exchange for less favorable treatment with respect to other contractual provisions such as profit share. An implicit option may also exist to the extent that a reduction in exploratory well commitments can be obtained by offering additional seismic work. In the case of such trade-offs, the ability to quantify the value of the seismic option is a necessity. This paper presents a framework for this valuation.