bluuebunny/crossref_metadata_2025 huggingface dataset:
Effect of Pore Structure and Residual Oil on Polymer Bridging Adsorption
Authors: Zaitoun A. , Chauveteau G.
Published: December 2007

In a preceding study, we observed a new type of polyacrylamide flow-induced retention in core experiments simulating nearwellbore flow conditions. This retention is due to the bridging of pore throats by adsorption of macromolecules previously stretched under elongational flow. It was shown to occur at high shear rate only in low-to-medium permeability granular packs (up to k = 1200 mD in our test conditions) and lead to progressive but severe plugging. Further investigations on this polymer retention process are reported here. To study the effect of heterogeneity in the pore structure, we ran experiments with mixed-grain granular packs and with Berea sandstones. Heterogeneity is unfavorable for the bridging adsorption process, because the time for relaxation of stretched macromolecules between two elongational zones is increased. Moreover, when there is a sufficient fraction of pore throats too large to be bridged by stretched macromolecules, the process leads to maximum stable values for both mobility and permeability reductions above a critical injection rate. In Berea sandstones, bridging adsorption occurs first in the smallest pore channels. Then, as the injection rate increases, more and more pore channels get bridged up to the maximum level mentioned above.

The presence of residual oil in the core reduces the average size of the pore channels for the aqueous phase. It is thus a factor that enhances the bridging adsorption process. In granular packs, the onset of polymer bridging adsorption occurs at lower injection rate when residual oil is present in the core. Moreover, for a given injection rate, the intensity of core plugging is higher at than at 100% water saturation. Since Berea sandstones are strongly water wet, residual oil reduces drastically the hydrodynamic pore size. For low-permeability Berea at residual oil saturation and low injection rate, we observe progressive plugging due to polymer retention upstream pore throats whose effective size is smaller than macromolecule size. At higher injection rates, this hydrodynamic retention vanishes, and the bridging adsorption process becomes dominant. Bridging adsorption induces the same behavior as without residual oil, i.e. a progressive bridging of pore channels up to a maximum level due to the existence of very large pores that cannot be bridged by stretched macromolecules.

P. 209
Adsorption of Linear Flexible Polymers During Laminar Flow Through Porous Media:
Authors: Zitha P.L.J. , van Os K.G.S. , Denys K.F.J.
Published: December 2007

Polymer solutions for water control are usually injected at a relatively high concentration (i.e. the semi-dilute regime). During placement entangled polymer chains can be retained by a collective adsorption and bridging mechanism. This results in polymer loss near the face of the wellbore and in an inefficient reduction of water relative permeability.

The data on the effect of collective adsorption of entangled chains are scarce in literature. In this experimental study we are concerned with the influence of polymer concentration and permeability on the retention of high molecular weight non-ionic polyacrylamide (PAAm) during flow in granular porous media (packing of silicon carbide). Thus far we have made the following observations.

At low polymer concentrations (the dilute regime) polymer injection leads to a gradual increase in pressure drop. Finally the pressure drop levels off to a plateau indicating steady-state flow. It is known that the delay in the polymer displacement front is related to the amount of adsorbed polymer. At higher concentrations (semi-dilute regime), however, no steady state flow seems to be reached within the duration of the experiments. Furthermore the residual flow resistance, determined by water flow following polymer, increases with polymer concentration. These effects can be explained by a mechanism of collective retention of entangled chains, which are adsorbed and bridge over pore constrictions.

P. 225
Smart Foam to Improve Oil Recovery in Heterogeneous Porous Media
Authors: Tsau Jyun-Syung , Yaghoobi Hossein , Grigg Reid B.
Published: December 2007

The addition of surfactant in brine during a water alternating with CO2 (WAG) injection or co-injection with CO2 process has proven to produce foam that reduces CO2 mobility. Laboratory experiments have shown that some surfactants generate "smart" foam that selectively reduces mobility of CO2 by a greater fraction in lighter than in lower permeability cores. The occurrence of such an exciting property in foam displacement and its application to improving oil recovery in heterogeneous porous media are discussed in this paper.

In our latest work that experimentally simulated the heterogeneous characteristic of reservoirs, we used composite cores that contain coaxial zones of high and low permeability either in capillary contact or isolated from each other. Experiments were performed on core systems both with and without oil saturation. Smart foam was injected into these core systems and its performance was determined by the breakthrough time of CO2 and fluid recovery in each well-defined permeability region.

Our results demonstrate that smart foam is useful in correcting nonuniform frontal displacement due to the heterogeneity of a reservoir formation. Smart foam is also very effective in displacing the oil-a benefit frequently overlooked by researchers testing the foam aspects of mobility control.

P. 247
Effects of Foam Quality and flow Rate on CO2-Foam Behavior at Reservoir Conditions
Authors: Chang Shih-Hsien , Grigg Reid B.
Published: December 2007

This paper reports a series of steady-state CO2-foam flow experiments performed at reservoir conditions of 101 F and 2100 psig. The effects of foam quality and flow rate on foam flow behavior were investigated. The foam experiments were conducted by injecting CO2 and surfactant solution simultaneously into a core saturated with surfactant solution at various total flow rates and foam qualities (CO2 fractions). A commercial surfactant (Chaser TM CD 1045) was used at 2500 ppm concentration in a 4 wt% synthetic brine.

Our results have shown that the foam mobility (total mobility of CO2/surfactant solution) decreased with increasing foam quality ranging from 20% to 80% for flow rates of 4.2, 8.4, and 16.8 cc/hr. The foam resistance factor increased with increasing foam quality ranging from 33.3% to 80% for flow rates of 4.2, 8.4, and 16.8 cc/hr. A minimum foam resistance factor was found between foam qualities of 20% and 33.3% for flow rates of 8.4 and 16.8 cc/hr. The foam mobility increased with increasing flow rate ranging from 4.2 to 16.8 cc/hr for foam qualities of 20%, 33.3%, 50%, 66.7%, and 80%. Also, the resistance factor decreased with increasing flow rate ranging from 4.2 to 16.8 cc/hr for foam qualities of 20%, 33.3%, 50%, 66.7%, and 80%.

P. 265
Foam/Oil Interations at Reservoir Conditions
Authors: Mannhardt K. , Novosad J.J. , Schramm L.L.
Published: December 2007

Foam mobility reduction factors (MRF's) were measured through foam floods in Berea and North Sea sandstone cores with three conventional surfactants (Chaser GR-1080, Enordet X-2001, and Dow XSS-84321.05), either by themselves or mixed with a fluorinated surfactant (Fluorad FC-751), at 75 C and 13.8 MIPa. Several other experimental methods were also used to evaluate possible correlations in foam performance: bulk foam stability, etched-glass micromodel observations, and interfacial parameters.

The presence of oil reduced foam MRF's of different surfactants to different degrees. Excellent MRF's were still attained with Chaser and Enordet in the presence of residual oil, while Dow was ineffective. The addition of Fluorad enhanced the oil tolerance of Chaser and Dow foam, but did not provide any benefit to Enordet. MRF's measured in an oil-free North Sea reservoir core were lower than in Berea core, but were affected relatively less by oil. The tested foams exhibited oil transporting properties. Each foam adjusted to its own residual oil saturation and corresponding level of mobility reduction. Foam performance in core floods did not correlate in general with predictions based on the other experimental methods.

P. 287
A Feasible New Flue Gas CO2 Recovery Technology for Enhanced Oil Recovery
Authors: Iijima Masaki
Published: December 2007

Mitsubishi Heavy Industries, Ltd. (MHI) and The Kansai Electric Power Co., Inc. have been developing flue gas CO recovery technology since 1990 as a measure against Global Warming. As a result of the research and development efforts which have now been carried out for seven years, the new energy-efficient solvents KS-1 and KS-2 which are less corrosive and cause less degradation than those used previously, have been developed. In addition, a research has produced a new packing, KP-1, that can reduce the size of CO2 absorbers and the horsepower requirements of flue gas blowers. The pilot plant, which is located in Nanko Power Plant of The Kansai Electric Power Co., Inc. has been used for the pilot tests of The Central Electric Power Council targeted for all utility companies in Japan and MHI since the fiscal year of 1995. The newest developments are presented in this paper, as well as a cost study of power plants flue gas CO2 recovery and compression to evaluate application of the technology for enhanced oil recovery. This new flue gas CO2 recovery technology, in comparison with the conventional technology (Monoethanol Amine Process), dramatically reduces the CO2 recovery cost. A cost evaluation study reveals, if the power plant is located near the oil field (a couple of hundred kilometers), it is feasible to supply CO2 at 1 USD/MSCF or below, while if the fuel (gas or coal) cost is around 0.5 USD/MMBTU, CO2 recovery and compression cost can be reduced to 0.7 USD/MSCF. These CO2 delivery costs are equivalent to CO2 delivery cost in the United States for enhanced oil recovery.

P. 333
Bu Attifel Field (Libya): Improvement of the Microscopic Efficiency of Oil
Authors: Causin Emilio , Passucci Claudio , Rossi Elio , El-Ageli Ibrahim Salem
Published: December 2007

The Bu Attifel field is a giant reservoir located in the Sirte Basin in the Libyan desert. It was discovered in 1967 at an average depth of 4,200 m s.s.l. and produces volatile oil (41 API) from continental sandstone. The crude is paraffinic with wax content of 36.7% and high pour point temperature (39 C).

A water injection project was set up in 1974. Since water production has increased considerably in the last five years, the feasibility of an EOR tertiary process is being studied to improve the final oil recovery. The miscibility of three different gasses (carbon dioxide, lean gas and enriched gas) with the reservoir oil was evaluated through lab experiments performed at the average reservoir temperature (145 C). At the current reservoir pressure (40.5 MPa), the lean gas enriched with liquefied petroleum gas (LPG) appears to be the most efficient solvent.

This paper describes lab experiments carried out to evaluate the microscopic efficiency of oil displacement using enriched gas under current reservoir conditions.

Several tests were carried out using reservoir core plugs, selected on the basis of Nuclear Magnetic Resonance Imaging analysis. Three different reservoir conditions (residual oil saturation, intermediate oil saturation and irreducible water saturation) were simulated.

Most of the tests demonstrated the very high displacement efficiency of the enriched gas as regards final oil recovery. Gravitational forces slightly influenced oil recovery, while an important role was played by rock texture when samples at residual oil saturation were considered.

P. 343
Screening and Evaluation of Modified Starches as Water Shutoff Agents in Fractures
Authors: Barrufet Maria A. , Burnett David , Macauley Julian
Published: December 2007

In the past, starch hydrocolloids have not been effective alternates to partially hydrolyzed polyacrylamides, copolymers and xanthan gum polymers as water shutoff agents in fractures and in matrix flow configurations. Poor injectivity and questionable stability have prevented their use in profile control applications. However, chemically modified starches have properties suitable for improved recovery technology. They do not hydrolyze in harsh saline environments, are made more resistant to biodegradation, and because of their wide spectrum of molecular weight distributions can be tailored to specific lithologies. The development of new materials with superior functionality and reliability has been among the most important technological advances that can significantly increase oil and gas reserves and reduce production costs.

Chemically and/or physically modified starch polymer samples were subjected to preliminary screenings involving rheological tests, sedimentation tests, and stability tests at varying pH and temperature. The samples passing these tests were selected for core flow testing.

The functionality of a new generation of modified starches was evaluated for profile control applications in matrix and in fracture flow configurations.

A new type of fractured core cell was designed and constructed for testing the polymer samples. The device allows the aperture of the fracture to be set independently during the experiment.

Results to date in the evaluation of modified starches are very encouraging. Specific materials have been identified that have the necessary stability under reservoir conditions for extended time periods. Testing in porous media indicate that certain types of the polymers have sufficient injectivity to allow propagation out into the reservoir matrix. Crosslinked polymer gel systems indicate that the modified starches may offer an alternative to currently used polyacrylamide, particularly for lower temperature systems, because of lower reaction times and adequate retention properties in porous media and in fractured core systems.

P. 363
Role of Diffusion Mass Transport in Design of Profile Correction Methods Based on
Authors: Lakatos I. , Lakatos-Szabo J. , Kosztin B.
Published: December 2007

The diffusion of different component of self-conforming phases injected sequentially into the reservoir may influence significantly the efficiency of profile correction in the vicinity of wells. Unfortunately, the possible role of diffusion in such procedures either is not detailed in the literature or itis considered as a negative of mechanism. Therefore the laboratory studies were focused on analysis of diffusion transport of Cr(III) and Cr(VI) ions in polymer/silicate gels used routinely for water shut-off treatment at the Hungarian oil fields. The effective diffusion coefficient, break-through time and ion retention capacity were determined as a function of the geometry, temperature and composition of gel. It was found that the effective diffusion coefficients were very close to the value characteristic in aqueous solutions and they are proportional with the radii of hydrated ions. The high retention of Cr(III) ions in gels was attributed to in-situ chemical reactions. mechanical entrapment and sorption. The diffusion mass transport of chromium ions could be described by the Fick's I. law in the equilibrium state.

It was found that the diffusion coefficient decreases, while the break-through time and ion retention increase with the solid content of gel. The relative effect of polymer is greater by an order of magnitude than that of the silicate content. The influence of gel components can be interpreted by a diffusion model elaborated originally for porous systems. It was also shown that the polymer concentration is mostly effective in increasing the tortuosity, while in case of silicate content both the porosity and the tortuosity must be considered. The laboratory experiments provided valuable information and data to design efficient profile correction and containment technologies in enhanced oil recovery and environmental protection.

P. 375
Polymer Transport and Rheological Properties for Polymer Flooding in the North Sea
Authors: Osterloh W.T. , Law E.J.
Published: December 2007

The Captain field in the North Sea UKCS is a highly viscous crude accumulation produced via waterflooding with extended reach horizontal wells. Captain's high oil-water mobility ratio and exceptional reservoir quality make it an ideal candidate for improved oil recovery by polymer augmented waterflooding. Polymer storage tanks and subsea polymer flowlines were included in the design and build of the Captain facilities to simplify future implementation of a polymer flood pilot.

Offshore logistical considerations led to the selection of liquid hydrolyzed polyacrylamide (HPAM) as a basis for the polymer flood design. We report in this paper the methods and results obtained from a series of laboratory studies undertaken to identify HPAM's that could be used at Captain and to provide data for reservoir simulation input. This work, conducted by the Operator and two polymer vendors, included coreflood tests, scaled polymer mixing tests, and polymer shear degradation tests.

Although good viscosity yield, low polymer retention, and good coreflood oil recoveries were obtained with HPAM's, the solutions caused face plugging of Captain cores. Using a membrane filtration method to quickly screen new products, both vendors developed improved HPAM's that were judged suitable for use in the Captain reservoir. Results of the shear degradation experiments indicated that shear degradation should be insignificant in tubulars at field design flowrates, but possibly substantial at the sandface.

P. 385
A Study of the Chemical Interactions Between Brine Solutions and Dolomite
Authors: Zou B. , McCool C.S. , Green D.W. , Willhite G.P.
Published: December 2007

Injecting gelant to change the flow characteristics of a reservoir is a viable improved oil recovery technique. Many gel systems are affected by the solution pH in that gel time is pH dependent. The treatment of carbonate reservoir rock is of particular concern because 1) fluid-rock interaction can alter the pH of the injected solution, moving the pH away from the design value and 2) dissolution of carbonate can increase the divalent ion concentration which can affect the gel behavior.

In this study, the interaction between injected potassium chloride brine and dolomite was investigated through displacement experiments in dolomite cores and mathematical modeling based on equilibrium thermodynamics. Parameters varied were pH of the injected solution, flow rate, and the common ion effect through variation of the calcium and magnesium ion concentrations in the injected solution. Core effluent values of pH and concentrations were measured. A geochemical model was used to predict equilibrium pH and concentrations, as well as the amount of dolomite dissolved. The model was compared to the experimental displacement data for the conditions wherein equilibrium was achieved. All model parameters were obtained from literature equilibrium data and were not dependent on curve fitting of the experimental data. Experiments at different flow rates established conditions in which equilibrium was achieved in the core.

The injected solution pH was varied between values of 2.6 and 11. The corresponding measured effluent pH values and simulated results could be divided into three stages. When the injected solution pH was less than 4, the effluent pH was much higher than the injected pH and increased with increasing injected pH. For injected pH values between 4 and 10, the effluent pH was almost constant at a value of 10. At injected pH values above 10, the effluent values were nearly equal to the injected values. At the lowest pH stage, effluent concentrations of Ca and Mg decreased exponentially as pH was increased. In the middle stage, the divalention concentrations were almost constant and not a strong function of pH.

When Ca and Mg were present in the injected solution, the dissolution of dolomite was depressed and effluent pH was lower compared to the cases where Ca and Mg were not in the injected solution. For a specified total divalent ion concentration in the injected solution, the presence of both Ca and Mg had a larger effect on equilibrium pH than did either species individually.

Pressure measured along the core during the displacement showed that dissolution of dolomite had an insignificant effect on rock permeability for the conditions of these experiments.

P. 397
Understanding Injectivity in Heterogeneous Reservoirs
Authors: Pizarro Jorge O.S. , Lake Larry W.
Published: December 2007

This paper introduces a novel approach to quantify the dependence of injectivity on the heterogeneity and auto correlation of the reservoir permeability distribution. The mathematical formulation of the problem was derived for two geometries representing a vertical cross section and a five-spot pattern. The heterogeneity is modeled by stochastically generated permeability distributions. The scaling of the governing equations, by inspectional analysis, generates a minimal set of dimensionless groups that is able to describe fracture-free injectivity in heterogeneous permeable media. The scaling procedure was validated against available analytical solutions and the importance of each dimensionless group on the dimensionless injectivity evaluated with an extensive set of numerical experiments. The results obtained provide a better understanding of how vertical well injectivity depends on heterogeneity and gives insight into why injectivity calculated from a core permeability average is frequently different from the injectivity manifested by the well in question.

P. 421
Control of Fluid Injection into a Low-Permeability Rock - 1. Hydrofracture Growth
Authors: Patzek Tad W. , Silin Dmitriy B.
Published: December 2007

This paper deals with growth of injection hydrofractures in transient linear flow in a low permeability, soft rock. Seventeen waterflood injectors in Section 12 of the Middle Belridge diatomite, three steam injectors in Section 29 of the South Beiridge diatomite, as well as forty four injectors in the Lost Hills I waterflood have been analyzed. The field data show that cumulative injection of water or steam scales with time to the power of 1, rather than V2 predicted from the theory of linear transient flow. In other words, at constant injection pressure, injection rate is remarkably constant. Therefore, either the injection hydrofractures grow with time, or the formation permeability increases with time, or both. A simple mass balance of hydrofracture growth during fluid injection, attributed to Carter, is corrected, extended to the case of variable injection pressure, and presented in a simplified form. The growth of fracture area at constant injection rate is expressed in terms of two easily measured field parameters, the early "injection slope" in linear transient flow, and the average injection rate. Carter's fracture growth rate is further halved to account for the reservoir layer homogeneity parallel and perpendicular to the hydrofracture plane. The Carter theory predictions are then compared with the growth rate of hydrofracture area calculated independently for two steam injectors in Section 29. There is remarkable agreement between the modified Carter theory predictions and the independently estimated rates of growth of these two hydrofractures. We show that fluid injection above a reasonable minimum rate must lead to hydrofracture extension if injection pressure is bounded from above. Ultimately, fracture growth is inevitable, regardless of mechanical design of injection wells and injection policy. We also show that water injection leads to less severe formation damage and fracture extension than steam. By analyzing the thermal and pore stresses, we demonstrate that steam injection may lead to the creation of horizontal fractures, vertical fracture extension, and reservoir damage. Better control of steam injection is, therefore, a must. We address the optimal injection control strategy in Part 2 of this paper.

P. 433
Optimization of Borate-Based Gels Used for Wellbore Diversion During Well
Authors: Al-Anazi H.A. , Nasr-El-Din H.A.
Published: December 2007

Borate-based gels are commonly used as fracture fluids. However, they can be used during well stimulation to divert the acid into the target zones only. The gelling system examined consisted of guar gum or its derivatives, a suspending polymer, a pH elevator, a cross-linker, and a chemical breaker.

Several gelling formulas were screened in the lab. Boron or zirconium was used as the cross-linker. The gelation time was measured as a function of temperature and gel composition. The effects of salinity and hardness of the mixing water on gel properties were studied. The apparent viscosity of the gelling solution was measured as a function of shear rate. Because the gel will be in contact with the acid, the rate of gel degradation by the acid was examined in detail.

The results indicated that the gelation time decreased as the temperature was increased. The effect of temperature on the gelation time can be predicted using an Arrhenius-type equation. The gelation time was found be a function of initial pH, cross-linker concentration, water salinity and hardness.

Acids (15 wt% HCl) reacted with the gel and formed a solid residue (brown particles). The amount of this residue was measured for various gels. A new technique was developed to determine the rate of gel degradation during field treatments.

A temporary gel was used on a horizontal water injector to block the open hole, and acidize the newly perforated interval only. The first treatment failed due to premature setting of the gelling solution inside the coiled tubing. Lab results indicated that the fast setting of the gelling solution was due to the presence of acidic contaminants in the mixing tank from a previous acid job. These contaminants lowered the pH of the gelling solution, and caused premature setting of the gelling solution. It was also found that a brine different from the field mixing water was used to measure the gelation time. The gelation time using the field mixing water was found to be less than that measured using the lab water by a factor of 6.

Several modifications were introduced to the gelling system and its field application was modified to avoid similar problems. The second treatment was successfully applied in the field, where the injection rate increased by a factor of 1.5. Measuring the concentration of boron in the acid returns confirmed that the acid broke the gel. Based on extensive lab/field work, guidelines to use the borate-based gels for zone isolation during well stimulation were specified.

P. 449
Integrated Asset Management: Work Process and Data Flow Models
Authors: Janele P. T. , Galvin T. J. , Kisucky M. J.
Published: December 2007

Reservoir characterization and flow prediction modeling form the fundamental basis of modern integrated Asset Management. As our oil industry evolves, increasingly sophisticated component technologies are being developed and applied in support of these characterization and modeling objectives. The oil industry is developing and embracing these new component technologies at a stunning pace - sometimes without full knowledge as to how each component might be consolidated into an overall solution to address real business issues.

Forging through the maze of available technologies to identify a process which will address a specific business question is a challenge that requires several insights: an understanding of the business objective and risk, an understanding of specific details as to what each technology offers and, an understanding of how each technology can be linked to form an overall solution. This is a complex quest which often results in uncertainty within both company management and employees who are unclear as to how any individual technology will "pay out" or how a particular subprocess will be used as part of a whole to "make a difference".

During ongoing efforts to evaluate new reservoir modeling technologies at Caltex, a team of Caltex specialists developed a combination work process/data flow model for reservoir modeling and characterization. The work/data process model definitions are expressed in the form of Reservoir Modeling Process (RMP) maps. These maps can be used to understand and define the overall objectives of an integrated team effort and accordingly allocate resources and project deliverables for Reservoir Characterization and Flow Modeling.

The RMP process maps are scaleable in that various degrees of sophistication, and commensurate business risk-reduction, can be implemented. Examples of RMP application and scalability are offered from the historic use within Caltex CPI Indonesia. Current limitations and future evolution of the RMP process maps is also discussed.
Evolution of Reservoir Management Techniques: From Independent Methods to an Integrated Methodology. Impact on Petroleum Engineering Curriculum, Graduate Teaching and Competitive Advantage of Oil Companies
Authors: Gringarten Alain C.
Published: December 2007

The reservoir management process integrates the following steps: (1) acquisition of data; (2) interpretation of each data type to obtain an interpretation model for the data; (3) integration of all available data interpretation models into a reservoir model; (4) calculation of the reservoir model behaviour with a reservoir simulator; (5) calibration of the reservoir simulator by history matching production data; (6) coupling the reservoir simulator with well and surface facility simulators; and (7) using the coupled simulators to calculate reserves and predict production for various development scenarios. This new concept in reservoir management has evolved in parallel with the re-organisation of oil companies into multi-disciplinary asset teams. These changes, however, have yet to reach most universities, which still teach each petroleum discipline as a separate subject, mainly because the various skills needed sit in separate departments. These historical barriers must be dismantled in order to give students the required understanding of (1) the fundamental concepts of reservoir characterisation, reservoir modelling, reservoir simulation, and field management; (2) the links between the various types of data; and (3) the processes for integrating and processing all available information. Another consequence of the new reservoir management methodology, coupled with the availability of commercial software enabling that methodology, is that results of reservoir management will become more predictable: given the same information, different teams applying the same methodology will reach the same conclusions, thus reducing greatly the advantage of technical knowledge in competitive situations.
Improving Profitability Through The Use of Dual and Quad Lateral Wells
Authors: Permadi P. , Wibowo W. , Sukotjo R. , Arsegianto _
Published: December 2007

Among multilateral well systems that can be drilled using today'stechnology, more than thirty dual and quad lateral wells have been successfully implemented in an oil field. The advantage gained over single lateral wells is an increased reservoir access per well drilled. There are some investigations dealing with inflow performance and economic evaluation of multilateral wells, excluding dual and quad laterals. Therefore, further reservoir engineering and economic studies should be conducted to evaluate the potential of these dual and quad well systems for improving the profitability of reservoirs.

The objectives of the present work are to study the effect of reservoir characteristics on the production performance of a dual and a quad laterals and to evaluate the economic attractiveness when compared with a single lateralwell. Based on the performance prediction model used and the economic evaluation, results obtained show that the use of such multilateral wells would be economically more attractive for reservoirs with low-to-medium permeability. Also found, on the basis of the comparison made here, that the economic benefits are influenced as well by the magnitudes of reservoir anisotropy, the lateral holes placement, and producing rate.

Overall, from a reservoir management point of view, the results demonstrate the importance of adequate reservoir characterization and the production strategy in the applications. P. 53
Total Asset Management Strategy for the McKee Field, New Zealand
Authors: Adams M.R. , Stoltz L.R. , Wadsley A.W.
Published: December 2007

The McKee Field, onshore New Zealand, was brought to commercial production during 1984 at 5000 BOPD. Production peaked at 12,000 BOPD in 1989 and was followed by a rapid decline over the next three years to 6000 BOPD at the end of 1992. At this time it was recognized that a proactive field management strategy was required in order to minimize any further decline in field production rates as the "Produce Out - Proven Developed" production forecast showed a continuous production decline. Six key areas of revenue enhancement were identified as implementation of waterflooding in McKee Central, aggressive appraisal drilling, production optimization, exploration in proximal horizons, operating expenditure reductions, and facilities/infrastructure issues. Twenty-eight activities were resourced with a target of sustaining production rates to the year 2000 and increasing remaining reserves from 8 MMbbl (as at 1993) to 21 MMbbl. The look-back analysis presented here describes this integrated approach to reservoir management and illustrates how it continues to meet its production and reserve targets despite unanticipated reservoir complexity.

P. 77
Optimising Multi-Field Developments Under Uncertainty
Authors: McGill Colin , Goodwin S. P. , MacGowan D. , Aissaoui A. , Riddiford F. A. , Standish I. G.
Published: December 2007

Subsurface staff have tried to include uncertainties in their predictions for some years (e.g. Smith, Hendry and Crowther1). Unfortunately, these are not normally carried through to the development design because of the time required to engineer all the possible solutions. This paper describes a systematic process for incorporating the uncertainty, using the optimisation tool described by MacGowan and Goodwin2.

In this method, optimum facilities are designed for several hundred reservoir configurations. These can be analysed to show which of the sub-surface uncertainties are responsible for major changes to the development. In turn, this information can be used to shape any proposed appraisal programme.

The sub-surface representation adopted by MacGowan and Goodwin is described in more detail. It is shown that the representation produces profiles which are in excellent agreement with profiles generated through full simulation. Given the level of reserve uncertainties, it should be possible to derive an adequate sub-surface representation for any other reservoir process, not just depletion of dry gas.

These ideas have been applied to the proposed District 3 development in the Algerian Sahara. The results have influenced the exploration and appraisal programme. In addition, they have provided tremendous insight into how uncertainty will affect the development.
Worldwide Fiscal Systems: How are Abandonment Costs Treated
Authors: Pittard A. J. , Davitt C. P.
Published: December 2007

The costs of the abandonment of a field development depend on the geographical location of the structures and the number of platforms for each field, the water depth, topside weight, jacket weight, type of structure, proximity to shore, availability of equipment and the level of removal required. Thus, the overall cost of removing existing platforms is difficult to predict but is estimated to be between US$29 to US$40 billion. Both government and operator's alike have a concern that abandonment costs are so high. But how are governments addressing these cost issues?

Firstly, it must be realised that governments hands are tied in many respects with regards to decommissioning, as they are locked into complete removal of obsolete platforms (and the high costs associated with this option) in water depths less than 75 metres due to the International Maritime Organisation (IMO) guidelines, the 1958 Geneva Convention on the Continental Shelf and the 1982 U.N. Convention of the law of the sea. Platforms in deeper water do have removal options for instance, partial removal, topple in place, rigs to reefs or leave in place. Each option has advantages and disadvantages. In all cases however decommissioning will take place and the costs will be high especially in the North Sea.

Decommissioning costs do not increase oil production, in fact revenue decreases at this stage in the production life cycle. Therefore to safe guard the environment and reduce the cost burden to the operators and in Production Sharing Contract regime countries to the government themselves, governments must introduce fiscal relief regulations for abandonment costs.

Of the 135 countries with fiscal terms available for this paper, approximately 34 countries had fiscal relief clauses.

This paper will discuss the abandonment fiscal clauses and present a hypothetical model which will illustrate the best fiscal relief options for the countries which presently have no fiscal treatment of abandonment costs.
Unlocking Development Potential of a Complex Faulted Marginal Oil Field, Offshore Sarawak: Integrated Field Study
Authors: Soo D. K. Y. , Hartemink M. , Kuud T.
Published: December 2007

This paper describes an integrated approach of building subsurface models for a complex, faulted marginal oil field in the Balingian acreage operated by Sarawak Shell. For the field described in this paper, the modelling highlights that sand development, fault compartmentalisation and internal shale baffles are the foremost important modelling parameters that have significant impact on the production. The impact of subsurface uncertainties has been quantified in terms of production using proprietary reservoir modelling software. The quantification of the impact of associated uncertainties defines the requirements for a surface structure and allows evaluation of the value of investments that are aimed at reducing the uncertainties.
Facility Risk Assessment and Risk Management in Offshore Oil & Gas Industry
Authors: Harmony Kunu
Published: December 2007

This program is operational in Chevron Nigeria Limited and was introduced as a framework for integrating risk assessment within a risk management system. Also, the risk assessment program was developed to provide a process for rapid screening of risk in order to focus attention on risk levels that need to be eliminated or minimized. The article examines the principles and techniques of risk assessment and risk management, and it illustrates their applications. It also describes how these techniques are used to prioritize decisions in preparing an effective ranking of risks within Chevron Nigeria offshore facilities. Risk assessment flowcharts, hazard identification, and risk assessment checklist were generated as a rapid guide to evaluation of the level of risks and to decide which risks would need more detailed analysis. The hazard identification has the following parameters as areas of concern Viz.: - Hazardous substances, Mechanical, Radiation, Electrical, Work Environment and Work Activities Hazards. The risk assessment checklist includes details safe condition and working mechanism of Pumps, Instrumentation, Pressure vessel, Storage tanks, Fired heaters, Exchangers, Emergency Response Program, Facility Layout/Sitting etc. P. 111
Advances in Field Data Capturing to Optimize Asset Team Reservoir Development Decision Process
Authors: Dassen Jos
Published: December 2007

Historically, one of the more time wasting procedures within asset teams in oil companies have been the reporting, duplication and filing of data which is generated in field locations. The workflow typically in use will create many duplicates of data before it finally finds its way to the end destination.

With the advances in communication, networking and database technology better solutions are available. We will propose a solution in which data is entered into a computer only once, at the field location, and then finds its way to the corporate database. Facilities and procedures need to be created to allow for quality control and data correction before data reaches the final destination.
3-D Reservoir Modelling of the Sirikit West Field, Phitsanulok Basin, Thailand
Authors: Ainsworth R. B. , Sankosik H.
Published: December 2007

The Sirikit West Oil Field lies within the Phitsanulok Basin of Central Thailand. It is a satellite of the main Sirikit accumulation. Within the field, the Lan Krabu Formation represents the main reservoir interval. It is interpreted as fluvio-lacustrine in origin. The three major reservoir sub-members (D, K1 and K2) are subdivided into 10 to 15 m thick parasequences bounded vertically by minor flooding surfaces. Each parasequence represents a progradational phase of mouthbar development which is terminated by a flooding event. A typical parasequence consists of facies progressing from open lacustrine claystone to delta front including mouthbars and channel sands, to floodplain sands and shales. Compared to the Main Sirikit Field, the same stratigraphic intervals in Sirikit West are up to three times thicker. This indicates a strong element of differential subsidence across the major bounding fault between the two fields.

The depositional and sequence stratigraphic models for the area were used as a basis for generating 3-D geological and property models. 3-D modelling was undertaken to determine reservoir architecture and reservoir property trends prior to a new phase of field development. The Shell proprietary correlation software package GEOLOGIX and 3D modelling package MONARCH were utilised to enable rapid evaluation of a range of geological and petrophysical scenarios. For example, differing correlation scenarios reflecting geological uncertainties such as reservoir continuity were generated using GEOLOGIX and rapidly screened in MONARCH. The 3-D models were used for volumetric calculations, well planning, static connectivity analyses of proposed wells and as the input for dynamic flow modelling.

Upscaling of the 3-D geological models was undertaken using REDUCE and dynamic reservoir simulation was performed using the MoReS simulator. History matching of the two geological models carried forward to the simulator suggested that the high reservoir continuity scenario is the most readily matched. The dynamic model is being used as a general reservoir management tool for forecasting, well planning, and for analysing further development options. Results indicate potential for further development and appraisal drilling of up to ten new wells to fully develop the field and achieve optimal oil recovery.
EOS Simulation and GRNN Modeling of the CVD Behavior of Retrograde-Gas Condensate Reservoirs
Authors: Elsharkawy Adel M. , Foda Salah G.
Published: December 2007

Currently, two approaches are being used to predict the changes in retrograde gas condensate composition and estimate the pressure depletion behavior of gas condensate reservoirs. The first approach uses the equation of states whereas the second uses empirical correlations. Equations of states (EOS) are poor predictive tools for complex hydrocarbon systems. The EOS needs adjustment against phase behavior data of reservoir fluid of known composition. The empirical correlation does not involve numerous numerical computations but their accuracy is limited.

This study presents two general regression neural network (GRNN) models. The first model, GRNNM1 is developed to predict dew point pressure and gas compressibility at dew point using initial composition of numerous samples while the second model. GRNNM2, is developed to predict the changes in well stream effluent composition at any stages of pressure depletion. GRNNM2 can also be used to determine the initial reservoir fluid composition using dew point pressure gas compressibility at dew point and reservoir temperature. These models are based on analysis of 142 sample of laboratory studies of constant volume depletion (CVD) for gas condensate systems forming a total of 1082 depletion stages. The data base represents a wide range of gas condensate systems obtained worldwide.

The performance of the GRNN models has been compared to simulation results of the equation of state. The study shows that the proposed general regression neural network models are accurate, valid and reliable. These models can be used to forecast CVD data needed for many reservoir engineering calculations in case laboratory data is unavailable. The GRNN models save computer time involved in EOS calculations. The study also shows that once these models are properly trained they can be used to cut expenses of frequent sampling and laborious experimental CVD tests required for gas condensate reservoirs.

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Performance Evaluation of Horizontal Wells
Authors: Kuchuk Fikri J. , Lenn Chris , Hook Peter , Fjerstad Paul
Published: December 2007

Horizontal wells have been drilled in many oil and gas reservoirs. Measuring or calculating the productivity of horizontal wells has been difficult because of their long length in the formation compared with vertical wells and because of the inadequacy of measurements during drilling and production. In this paper, we examine the performance of horizontal wells. First, we review the theoretical productivity of horizontal wells and examine the sensitivity of productivity to well and reservoir parameters. We then compare theoretical and actual productivities from horizontal wells in several oil fields to show that most horizontal wells do not produce at their full potential because of the effects of wellbore and near-wellbore formation conditions right after drilling on cleanup. Second, using field examples, we show that the new integrated production logging measurements can be used to assess horizontal well productivity by identifying productive zones, fluid entries, and determining the fluid distribution (oil, gas, and water) in the wellbore. We also show how reservoir heterogeneity affects the reservoir pressure distribution.

The field examples indicate that horizontal wells have permanent water sumps, regardless of whether they produce water. In these wells, we show that when a large percentage of the wellbore cross section is filled with water, reduced oil entry occurs. To assess the effect of the water sumps, flow restrictions, and noncontributing sections along the wellbore on the well productivity, a numerical model with actual well trajectories and openhole and production log measurements is used to estimate well productivity. These horizontal well performance simulations indicate 30 to 50 percent productivity reduction when they are compared with their full potential.

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Hybrid Streamline Methods
Authors: Ponting D.K.
Published: December 2007

Streamline techniques offer the possibility of high speed reservoir simulation, but existing methods have some limitations for example, the pressure field is frequently derived using the assumption of incompressible flow. Unlike conventional simulation, material conservation is not inherent in the method, but can act as a check on the accuracy obtained.

Using a pressure equation based on molar density variables, we extend the streamline technique to handle compressibility and depletion. The streamline update then becomes an alternative method of updating the composition field to the usual conservation equations. By using and comparing both methods we can assess the accuracy and speed gains obtained using the streamline approach.

The treatment of wells is an area of interest in streamline simulation. When a number of streamlines enter a producer cell the contribution from each must be weighted carefully, as this defines the solution in the vicinity of the well and the composition of the produced fluid. It should also be possible for fluids to pass through a well completion cell without being produced, for example in the vicinity of a strong aquifer. In order to treat near well effects in detail, we combine a streamline model for the bulk of the reservoir with a more general model near the well.

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