bluuebunny/crossref_metadata_2025 huggingface dataset:
Innovative Use of Horizontal Wells in Mature Fields Boosts Production/Reserves
Authors: Baack William , Latif Mahmoud
Published: December 2007

Many Gulf of Suez fields operated by the Gulf of Suez Petroleum Co. (GUPCO) were discovered in the early 1970’s and are in the mature stages of depletion, requiring application of advanced technology and multi-discipline focused teams to identify bypassed oil. These fields are structurally and geologically complex, with bypassed oil potentially underlying faults or gas caps in highly stratified reservoirs of varying rock properties. Significant vertical well development often precludes conventional application of horizontal well technology. Non-conventional application of horizontal drilling in the late stages of depletion has aided development of resources where vertical wells are not viable.

Several field examples are discussed and illustrate the innovative use of horizontal wells to boost production and reserves. Horizontal wells are used to drill under faults to intersect multiple layers of thick reservoirs and to explore areal extension of reservoirs. Horizontal wells are also used to intersect appropriate reservoir layers in gravity drainage and gas cap reservoirs to improve rate and recovery. In each of these cases, multi-discipline teams identified the development potential, planned wells to meet objectives, and used real time data to ensure objectives were met.

The concepts used in the these field cases are being applied to other GUPCO fields as multi-discipline teams are assigned to study them. Success in these applications of horizontal wells along with conventional application of horizontal wells is helping GUPCO to boost production and increase reserves from mature fields.
Wettability Evaluation of a Carbonate Reservoir Rock from Core to Pore Level
Authors: Al-Yousef H. Y. , Lichaa P. M. , Al-Kaabi A. U. , Alpustun H.
Published: December 2007

Wettability evaluation was performed during stages of as received, cleaned, and restored states on core samples from a Saudi Arabian carbonate reservoir. The wettability behavior from the chemistry of brine-oil-carbonate rock interaction was found to be neutral to slightly oil-wet. The pore-size distribution obtained from mercury injection data indicated that about 15–20 percent of the pore volume is not accessible to asphaltene particles in the crude oil. Therefore a mixed-wettability state can exist. These results were confirmed by the evaluation of the wettability of the cores using USBM and Amott techniques.

The wettability at the pore level was studied using Cryo-Scanning Electron Microscopy. Rock samples were examined at irreducible water and residual oil saturations during cleaned and restored states. At irreducible water saturation, both oil and brine were present in the intergranular macroporosity and intragranular macropores and micropores. At residual oil saturation, oil was found in the form of isolated globules in the cleaned case. After aging, the oil is more loosely distributed in the porosity and generally contacts the pore walls. This indicates an evolution toward oil wetness with aging. These results are in agreement with the changes of wettability indices obtained using USBM technique.
Resistivity Index and Capillary Pressure Hysteresis for Rock Samples of Different Wettability Characteristics
Authors: Elashahab B. M. , Jing X. D. , Archer J. S.
Published: December 2007

This paper presents the results of an experimental investigation into the effects of hysteresis (saturation history) on resistivity index and capillary pressure characteristics for some sandstone rocks of different wetting character. The drainage and imbibition resistivity index and capillary pressure measurements were carried out at equilibrium conditions using oil and brine with semi-permeable membranes. The displacing-cycle dependent hysteresis was also investigated experimentally. The resistivity profiles along the core length obtained from six potential electrodes enabled the assessment of equilibrium conditions, core and saturation heterogeneity and the end effects.

All test samples ( except for an oil-wet sample) were initially saturated with brine and placed in a multi-sample coreholder with a water-wet membrane at one end of the sample and an oil-wet membrane at the other end. A mineral oil was injected through the oil-wet membrane in incremental capillary pressure steps while a fixed back pressure in the water phase was maintained. At the end of the oil-displacing-water cycle, brine was then injected back through the water-wet membrane by decreasing the oil-phase pressure in steps until reaching the maximum entry pressure of the oil-wet membrane. To study the displacement-cycle dependent hysteresis the second desaturation cycle was performed on some samples from the oil saturation remaining after a water-flood at the end of primary saturation.

Our results indicate that both the displacing-phase and displacing-cycle dependent hysteresis should be taken into consideration for relevant resistivity index and capillary pressure curves. The hysteresis effects were also found to depend on the wettability of the rock samples. A parametric study was presented to highlight quantitatively the petrophysical effects.
Estimation of Condensate Dropout Effects on Well Productivity as Skin Change with Multiplicative Interactions Among Skin Components
Authors: Hwang M. K. , Odeh A. S.
Published: December 2007

This work deals with well productivity reduction due to altered formation permeability and other flow restrictions around a vertical wellbore. This near-wellbore formation change can be caused by liquid dropout in a gas condensate reservoir, for example. The corresponding reduction in well productivity can be quantified as an increase in the total skin (St). According to the conventional method, the total skin is given by a sum of individual components: St = Sm + Sp + Sd + Sa, where Sm represents flow restrictions from mechanical damage, Sp from partial completion, Sd from non-Darcy flow effect, and Sa from permeability reduction due to liquid dropout. The key finding of this work is that the total skin with condensate dropout can be much bigger than (Sm+Sp+Sd+Sa) due to nonlinear multiplicative fluid-dynamic interactions among skin components. These interactions have not been fully recognized and accounted for in literature. Two correct methods are presented for the total skin calculation in a multi-layered formation: direct simulation and heuristic analytical approximation. The analytical approximation equation is simple, but very accurate in most cases under the pseudo-steady state condition, when compared to the direct simulation method.

The new equation developed here has significant implications in various engineering analyses. The conventional method can grossly overestimate well deliverability, if the total skin value is computed from individual components. Conversely, when an individual component (such as Sm) is back-calculated from the total skin obtained from pressure transient analysis, the conventional method can grossly overestimate Sm. Also, this new equation can be used to predict simulation impacts of different wellbore description and of adjustments made in permeability distributions and skin components during history matching.
Transient Pressure Data Interpretation of Horizontal Wells in a Multilayered Reservoir
Authors: FURUYA M. , TAKAHASHI S.
Published: December 2007

This paper presents the results and the use of the interpretation of pressure transient data of a horizontal well in a multilayered heterogeneous reservoir. The well was drilled as a pilot horizontal oil producer with objectives to understand both the reservoir characteristics and the mechanism of water breakthrough in nearby producers due to pattern water injection.

Interpretation was first conducted using well test analysis packages, then the analytical results were verified by numerical simulation models.

This paper addresses the test interpretation findings and sets planning guidelines for pressure transient tests of horizontal wells.
Development and Application of the Water Control and Profile Modification Technology in China Oil Fields
Authors: Xiang-E Liu
Published: December 2007

This paper presents the research, development and field application of the water control and profile modification technology in China. It discusses on the mechanism of chemical water plugging and profile modification as well as matching techniques and the economic benefits in oil fields application.
Planning and Execution of a Record-Extended Reach Well in Japan
Authors: Benesch J. M. , Camacho A. G. , Matsuzawa S. , Dawson C. R.
Published: December 2007

The Johban Oki-2 well was drilled to a total depth of 4,984 m and reach of 3,881 m from the Iwaki platform located offshore Japan. Drilled and completed in 57 days during 1994, this well is believed to be the longest reach well in Asia.
Optimization of the Numerical Simulation in a Giant Oil Field by Upscaling of Relative Permeability Curves
Authors: Giliberti Stefano , Erba Mario , Rampoldi Maurizio , Said Ali
Published: December 2007

This paper presents the methodology applied to optimise the dynamic simulation of the giant Bu Attifel oil field (Libya) producing for 21 years under water injection.

When building the full field model of a giant field it is fundamental to limit the number of cells and CPU times without jeopardising the structural and sedimentological complexity of the reservoir. This will allow a correct simulation of future development phases, such as improvement in water injection (production-injection scheme optimisation, infill wells) and EOR processes (gas injection).

The first step of the study was the construction of two-dimensional cross sections based on the geological and dynamical data of the most representative wells. Then different oil displacement processes (water injection and gas injection) were simulated, mainly varying vertical communication and anisotropy of layers. Groups of relative permeability pseudo functions, consistent with the different geological configurations, were used in the full field model to simplify and optimise the history match phase.
Refloating Maureen Oil Platform (110,000 Tonnes) for Re-use in Waters Away From the North Sea
Authors: Tilling Geoff
Published: December 2007

The Maureen Oil Platform located in Block 16/29 of the UK continental shelf, North Sea has been in operation since September, 1983.

The fields that the platform serves are now nearing the end of economic production life and the operator, Phillips Petroleum Company United Kingdom Limited and its coventurers now have to decide how to most effectively abandon and dispose of the facility.

The platform is a three tank steel gravity structure. Each of the three "legs" is a cylindrical steel oil storage tank which sits on the seabed.

The platform utility and process plant is installed on the main deck, the lower deck and on a mezzanine level. There are five decks of accommodation and office modules sited on the main deck.

The three cylindrical storage tanks are normally fully flooded with water, crude oil or a combination of both, depending on the frequency of export to the offtake tanker. The tops of the storage tanks are at an elevation of 74 m above the seabed.

The platform is unique in its design, being the only steel gravity based structure in the North Sea.

The depth of water in which the platform stands is 95.6 m at L.A.T.

The platform was floated into location, already complete, and ballasted into position. In order to meet disposal regulation and international law its most likely removal will start with the entire platform being refloated.

As a free floating mobile platform it is available for use in any other waters of the world, subject to environmental and soil conditions.

This paper will demonstrate the work that has been carried out (and is continuing) to verify the refloat and marine stability of the platform as a vessel under tow. As an alternative, methods for transporting topsides and gravity structure separately followed by remating will also be discussed.

The paper will explain the platforms' processing capabilities, its flexibility as a work base and its excellent maintenance condition.
Study and Application of Positive Sol Drilling Fluid
Authors: Chun-guang Zhang , Wan-guo Hou , Dejun Sun , Tong-tai Xu
Published: December 2007

This paper reports a new drilling fluid system--positive sol drilling fluid (PSDF). The electrokinetic behaviour, rheological properties and the ability to inhibite clay swelling of positive sol (PS) and PSDF were studied. It was found that PSDF might form weak negative system and positive system under different conditions, and the gel strength and rheological parameters of PSDF could also be adjusted to meet drilling technology demands by changing the ratio of clay-sol. Both PS and PSDF demonstrate high inhibition ability, and PSDF can be treated with conventional additives. In this paper, the field test results of PSDF are introduced as well.
Field-Wide Compositional Simulation for HPHT Gas Condensate Reservoirs Using an Adaptive Implicit Method
Authors: Hsu H. H. , Ponting D. K. , Wood L.
Published: December 2007

The recovery mechanisms of high pressure and high temperature (HPHT) gas condensate reservoirs consist of pressure depletion, water encroachment, rock compaction and condensate banking near a well bore. The last two mechanisms require special treatments in a reservoir simulation model: the rock compaction leads to permeability reduction with declining pressure while the condensate banking requires small grids around a well. The condensate banking, which affects well productivity, was successfully simulated with a compositional simulator using radial local grid refinement within a Cartesian global grid system. A benchmark study was conducted to ensure the correctness of the local grid refinement.

An adaptive implicit method (AIM) was implemented which solves the local and global grids simultaneously. However, by making the local grids implicit, one avoided the time step restrictions which would otherwise occur due to their high throughput rates. In solving the linear equations which arose from the coupled local-global system, the grid ordering was found to be important. The optimal ordering proved to be that in which the local grids were placed before the global. This technique resulted in reduced computing time as well as robustness in dealing with field size models.

The solution technique was applied to a HPHT gas condensate prospect in the Central Graben region of the North Sea. This paper will address the recovery mechanisms regarding the rock compaction and the condensate banking. In addition, it will discuss the simulation of hydraulic fracturing as a means of improved recovery. Finally, it will present some experimental data that form the basis for input to the simulation model.
Scale Prediction and Prevention Technologies in Low-Permeability Reservoir During Waterflood
Authors: zhu Yiwu , zhao Zuozi , Ju quanyi , Wu Ping cang
Published: December 2007

Scale could be formed in Waterflood formation during the water injection development owing to the water incompatibihty and the variations of thermodynamic conditions and etc. This paper presents a computer model for predicting the sulfate scaling tendency along with the study of chemical control actions and technologies of reservoir scaling. Results of the technologies are evaluated according to applications in the field.
The Flow of North Slope Crude Oil and Its Emulsions at Low Temperatures
Authors: Rose S.C. , Marsden S.S.
Published: December 2007

This paper describes work that was carried out to determine the nature of low temperature flow through pipes of Prudhoe Bay crude oil and its emulsions with synthetic brine. These fluids were prepared and pumped both at temperatures ranging from 10 degrees to 30 degrees F and also at room temperature through a flow system consisting of a reservoir, a pump, a copper tube heat exchanger, a tubular flow resistance, and a return line to the reservoir. The heat exchanger and the flow resistance were immersed in a constant temperature bath (water and methanol) that could be adjusted to various temperatures. The pressure drop across the resistance and the viscosity of the fluids were observed and recorded.

The variation of viscosity with temperature and with emulsion quality (ratio of oil volume to total volume) was studied. A significant lowering of the apparent viscosity and of the pressure drop through the flow resistance was pressure drop through the flow resistance was found using emulsions as compared to the crude oil. Pumping an oil-in-water emulsion ma significant advantages in a Trans-Alaskan pipeline. pipeline

Introduction

The flow of emulsions in pipelines has received little attention in the petroleum industry. In particular, no work appears to have been done on the subject of emulsions flowing at low temperatures. Nevertheless, the subject may have considerable impact on the industry in light of the recent discoveries of very large oil deposits on the North Slope of Alaska.

An emulsion has been defined as "….. a heterogeneous system consisting of at least one immiscible liquid intimately dispersed in another in the form of droplets." An emulsion has two phases, the continuous and the dispersed. An phases, the continuous and the dispersed. An oil-in-water emulsion (O/W) has water as the continuous phase and a water-in-oil emulsion (W/O) has oil as the continuous phase. The experiments described in this paper deal with both types although the primary emphasis was on the oil-in-water emulsions.

Most studies of the rheology of emulsions have been done at or above room temperature. The only actual work done at low temperatures was concerned with the effect on the stability of emulsions through a freezing and then a thawing process.

The effects of various parameters on the viscosity of emulsions have been studied extensively, although not at low temperatures.
Bilinear Flow Regime Occurring in Horizontal Wells and Other Geological Models
Authors: Du Kuifu , Stewart George
Published: December 2007

This paper mainly describes how the bilinear flow regime can occur in various geological situations including a horizontal well in a dual porosity reservoir, a vertical well in leaky channels or near a high conductivity fault. A particular emphasis is put on illustrating the occurrence of the bilinear flow nature at intermediate time dual porosity response of horizontal wells.
Geological Modelling of a Structurally Complex Reservoir
Authors: Puliti Alessandro , Erba Mario , El-Ageli Ibrahim
Published: December 2007

This paper presents the technical problems faced and the solutions found in the construction of a suitable static model of Bu Attifel field.

The re-interpretation of the seismic volume, the construction of a detailed sedimentological model and the accurate correlations within the reservoir allowed the identification of several tectonic phases and, particularly, the intra-Nubian tectonics affecting only the lower levels of the reservoir.

The conclusions of the geological study led to the identification of a very complex structural model due to the number, slope and, often, synsedimentary characteristics of the faults crossing the reservoir.

During simulation, it was not possible to apply the usual simplifications to the structural model since a dynamic model able to optimise future infill well locations and enhanced oil recovery processes was required.

It was then decided to build a simulation grid reconstructing both fault trend on the horizontal plane and their slope as accurately as possible.

To this purpose, a specific methodology was followed. It consisted of two main phases: the generation of a conventional model with vertical faults and the conversion into a model containing sloping faults.

The final result was the construction of a geological model and a simulation grid representing the structural complexity of the reservoir.
The Construction And Application of Stochastic Models in Early Evaluation Phase of Oil Reservoirs
Authors: Wen Jian , Qiu Yi-Nan , Liu Ming-Xing , Xiao Jing-Xiu
Published: December 2007

In recent years, stochastic modeling technique has become a hot topic in reservoir characterization. Wherease, what should be made clear, if the technique is used in constructing geological models in early evaluationphase, is what problems in oil-gas development study can be solved by this technique. In this paper, focusing on the early evaluation phase of reservoir, the application cases from two reservoirs are used to discuss what practical problems can be solved by sectional reservoir models, which were built up by means of this technique.
Reservoir Characterization Using Model Based Seismic Lithology Inversion – Xijiang 24-3 Field, Pearl River Mouth Basin, Offshore PRC
Authors: Sharrah K. L. , Brumbaugh D. L. , Neff D. B. , Lun Ye Xiao
Published: December 2007

Mapping of sand thickness and porosity was enhanced in the Xijiang 24-3 Field by incorporating the results of a model based seismic lithology inversion process. The method successfully predicted an area of anomalous high porosity*thickness in a pay sand. The porosity data volumes generated by the method are being used in the 3D reservoir simulation for the field.
Corrosion Protection Of Oil Gas Seawater Submarine Pipeline For Bohai Offshore Oil Field
Authors: Chengde Zhu
Published: December 2007

The submarine pipelines for transporting oil, matural gas, seawater is a permanent project with giant investment. This project has been required to protect more than twenty years under the condition without maintenance. But in marine environment with harsh corrosion, we must anticorrode very well to it for safe service above twenty years.

Accoding to a long—term development practice for oil and gas in Bohai Offshore Oil Fields, this article synthetically describes internal and external corrosion control method of various types of submarine pipeline for traspporting oil, gas and seawater, mainly discusses the characteristic, fabrication, construction technical requirement and quality contral requirement for external corrosion coating, riser coating and joint coating for oil, gas and seawater pipelines, also discusses interrelated technical problems for design of cathodic protection system, fabrication, installation, inspection of sacrificial anodes when using Aluminium—Zinc— Indium system anode carries out cathodic protection of submare pipeline, as well as the suing method to prevent internal corrosion of pipeline from corrosive medium in oil, gas and seawater. At the same, the paper also shows adopted national rule and standards in anticorrosion design, fabrication, installation of submarine pipelines.
Wax Deposition Measurement and Scale-Up Modeling for Waxy Live Crudes under Turbulent Flow Conditions
Authors: Hsu J. J. C. , Brubaker J. P.
Published: December 2007

A wax deposition scale-up model has been developed to scale-up laboratory wax deposition results for waxy crude production lines. The wax deposition model allows users to predict wax deposition profile along a cold pipeline and predict potential wax problems and pigging frequency. Consideration of the flow turbulence effect significantly increases prediction accuracy. Accurate wax deposition prediction should save capital and operation investments for waxy crude production systems.

Many wax deposition models only apply a molecular diffusion mechanism in modeling and neglect shear effect. However, the flow turbulence effect has significant impact on wax deposition and can not be neglected in wax deposition modeling. Wax deposition scale-up parameters including shear rate, shear stress, and Reynolds number have been studied. None of these parameters can be used as a scaler. Critical wax tension concept has been proposed as a scaler. A technique to scale up shear effect and then wax deposition is described. For a given oil and oil temperature, the laboratory wax deposition data can be scaled up by heat flux and flow velocity. The scale-up techniques could be applied to multiphase flow conditions.

Examples are presented in this paper to describe profiles of wax deposition and effective inside diameter along North Sea and West Africa subsea pipelines. The difference of wax deposition profiles from stock tank oil and live oil is also presented.
Design and Performance of Chuchupa 14 - First Horizontal Gas Well, Offshore Colombia
Authors: Huang W.S. Bill , French Mike R. , Markitell Barry N.
Published: December 2007

In November 1992, a 2000-ft horizontal well was drilled in the Chuchupa Field, offshore Colombia. Chuchupa is a major gas field in Colombia, contributing about 90% of the gas supply for electricity generation on the northern coast of Colombia. This paper documents the selection, planning, reservoir simulation, drilling, completion and operation phases of this project. The horizontal well, Chuchupa 14, was successfully drilled from an offshore platform in 200 ft of water with a total horizontal displacement of 2000 ft. The entry point of the horizontal well is 6300 ft away from the platform. The formation is a semi-consolidated Chuchupa sandstone at a depth of 5325 ft sub sea, with average thickness of 167 ft, and average permeability of 209 md. Initial production test indicated that the well could be produced at 60 MMSCF/day on a 44/64" choke. This production rate is 4 to 6 times that of a conventional vertical well. Currently, the well is being produced from 40 to 60 MMSCF/day. In this application, the horizontal well can replace at least four vertical wells. With the development of horizontal wells, a significant amount of savings can be realized with fewer platforms and wells needed to develop the remainder of the field.

INTRODUCTION

The natural gas in the northern coast of Colombia is primarily supplied by two gas fields jointly operated by the Texas Petroleum Company and Ecopetrol. The Ballena Gas Field and the Chuchupa Gas Field in the Guajira area, shown in Figure 1, provided more than 90% of the gas supply for electricity generation in the coastal area. While the Ballena Field is partially onshore, the Chuchupa Field is about 7 miles offshore. The original gas in place for Ballena and Chuchupa are 1.5 and 4.2 TCF, respectively. Gas recovery in both fields is 30% and less than 30%, for Ballena and Chuchupa, respectively.

According to a previous reservoir simulation study, some of the existing wells in the Chuchupa Field may face water breakthrough in a near future, therefore replacement wells are needed to insure a continuous supply of gas from this field. Horizontal wells are one of the option to be considered.

BACKGROUND

Figure 2 shows the isopach map of the Chuchupa Field with its discovery well Chuchupa 1 near the center of the field and the 8 vertical producers drilled from the platform. When the field was first placed on production in October 1979, the rate was at about 100 MMSCF/day. As of December 1991, 450 BCF of gas had been produced from the field with the average production rate of 104 MMSCF/day or 13 MMSCF/day/well for the 12 year period. Before the horizontal well was drilled, production from the eight vertical wells was 140 MMSCF/day.
World Record Drain Hole Revives Production from a Barren HP-HT Well
Authors: Uboldi V. , Schenato A. , Fratus A.
Published: December 2007

Willingness to revive production from a High Pressure-High Temperature (HP-HT) well, characterized by poor productivity performance, led to the project of drilling a reentry horizontal drain hole at 5, 500 m TVD. The initial well, drilled and completed in early 1993, hit the target in an area of unusually poor petrophysical characteristics, where the fractures of the dolomitic reservoir were found to be filled with sedimentary dikes.

As a consequence, the well productivity performance was remarkably lower than expected, and the well was soon shut-in.

The well, named Trecate 14, was drilled in the Trecate-Villafortuna field (the biggest and deepest onshore producing oil field in Europe, located in the north-west part of Italy) at 6, 241 m TVD. Wells in this field feature production rates of about 4, 000 bopd, with flowing well head pressures of 400 bar (5, 700 psi) and temperatures of 120°C. The original reservoir pressure is over 1, 000 bar (14, 500 psi) and temperature as high as 170°C–180°C.

Studies undertaken by Geologists and Reservoir Engineers show that an area with suitable petrophysical characteristics could exist nearby the actual bottom hole location, some 150–300 m away.

A technical and economical proposal to recover this multimillion well to profitable production was submitted and approved by Company's Management.

In order to ensure maximum success, as well as achieving a certain offset from the initial wellbore, a certain horizontal displacement was required to increase chances of crossing good producing fractures. Following the 7" casing window milled at 5, 489 m, the drain hole was drilled to 5734 m measured depth; 64 m were drilled horizontally. Drilling was stopped due to repeated heavy mud losses which, on the one hand almost prevented the drilling operations being continued in a safe manner, while on the other hand indicated that potentially good producing fractures were crossed.

The successful conclusion of this project demonstrated the feasibility of ultra-deep drain holes under limited conditions such as those mentioned.

Furthermore, it demonstrated that it is feasible to use currently available technology with only minor modifications, provided that suitable procedures and contingency plans are implemented in advance.

The well was completed introducing modifications in the standard completion design used for other wells in the field. At present, the well is the best field producer.
The Viscoelastic Behavior of HPAM Solutions in Porous Media and It's Effects on Displacement Efficiency
Authors: Xian-Qing Han , Wang Wei-Ying , Xu Ying
Published: December 2007

The viscoelastic behavior of HPAM solutions and its effects on oil recovery were studied by means of core flowing tests and mathematical modelling. The mechanism of improving displacement efficiency due to viscoelastic effects was explained. This paper first presents a method to determine the first critical velocity (or critical viscoelastic velocity), Vce, at which the straining flow occurs. The experimental results indicated that the Vce increases with increasing permeability of porous media. Vce less than 1 m/d was observed.

There is a second critical velocity (or critical transit velocity), Vcr, at which the rheological behavior of HPAM solution transits from pseudoplastic to dilatant behavior. Vcr can be also determined through experiments. Vcr ranges from 1.74 to 3.30 m/d and also increases with increasing permeability of cores in our experiments. Within the range from Vce to Vcr, elongational flow occurs although the HPAM solution still exhibits pseudoplastic behavior. Beyond Vcr, the strain viscosity increases rapidly with velocity and straining flow governs the flow behavior. The results from core flowing tests showed that the displacement efficiency evidently increases with the velocity beyond Vce and reaches a maximum when the velocity approaches Vcr. The model index B (renamed Han’s index in this paper) describing the viscoelasticity of HPAM in porous media [1] has been proved to be the relaxation time for HPAM molecules[2]. The effect of property parameters of both porous media and polymer solution on Han’s index, H, was investigated by core flowing tests with artificial cores. The property parameters include injection rate, salinity, hydrolysation degree of HPAM and core permeability. A comprehensive Han’s index, He, was obtained as a function of these parameters by using multi-variable regression. Polymer flow tests in cores showed that the relative increment of displacement efficiency varies with He as a normal distribution function, i. e., there exists a optimum He which leads to a maximum of the oil recovery.

To investigate the influence of the rheological behaviour of HPAM on the prediction of on recovery in polymer flooding, one dimensional numerical simulation was conducted.

It is believed that viscoelastic behaviour will inevitably occur during HPAM solution flushed through oil formation and it plays an important role in oil recovery. Viscoelastic property of polymers should be considered as a screening criterion and it is necessary to take into account the viscoelastic effect in polymer flood numerical simulation.
Innovative Technologies Improve The Profitability Of Offshore Heavy Oil Marginal Fields.
Authors: Giuggioli A. , De Ghetto G.
Published: December 2007

The paper summarises a conceptual study carried out by AGIP for the development of offshore marginal heavy oil fields in the Adriatic sea (Italy).

On the basis of this study a comprehensive R&D programme was started, in order to validate the innovative technologies proposed.

The considered field size, with OOIP in the order of 80-140 million of ST bbl and the quality of the oil with a gravity around or less than 10° API, makes the conventional production schemes economically non viable.

The paper discusses some alternative development schemes based on the following innovative technologies. Fluidification and transportation of heavy oils via oil-water dispersion;Artificial lift of heavy oils with jet pump by using water as motive fluid;Multiphase pumping of the produced oil-water emulsion, from platform to shore;Light, reusable, unmanned platform.

A comparison of the principal economic indicators of the innovative proposed solutions versus the traditional ones is presented.

The new production schemes allow development of offshore heavy oil fields with costs saving of as much as 30 %.
Marginal Oil Fields, Profitable Oil at Low Reserves : How?
Authors: Agiza M. N. , Shaheen S. E. , Barawi S. A.
Published: December 2007

Fields with recoverable reserves of about five million barrels of oil are considered in Egypt as marginal fields. Economics of Egyptian marginal oil fields depend on non-traditional approaches followed in developing and operating such fields.

The actual exploration, development and operating expenses and state fiscal terms were used to evaluate the sensitivity of the economic parameters of such marginal fields. The operator net present value (NPV) and internal rate of return (IRR) beside the government take are presented for different parameters used.

The purpose is to make acceptable profits out of the marginal oil fields, for the mutual benefits of both the country and the investors.
Evaluating Shareholder Value of Investment Prospects - Usefulness of Per Unit Costs and Netbacks
Authors: Radke G. A.
Published: December 2007

Projected finding & development costs and netbacks, when used as investment decision criteria in conjunction with the capital productivity index, are useful for selecting an optimal corporate investment portfolio. The capital productivity index is an excellent measure for ranking investments and for optimizing the use of capital resources. Projected finding & development costs and netbacks measure the potential competitive advantage created by an investment, and the message that will be communicated to investors regarding an oil & natural gas corporation ‘ s competitiveness.

These criteria should be used with caution when used to compare investment prospects across different fiscal regimes. Governments collect their take through a variety of royalty, production sharing, and general corporate tax provisions, often in differing amounts and proportions. As a result, the implications of some of the terms inherent in the definitions could be different.

A useful graphical strategic planning tool can be developed by plotting calculated capital productivity indices against varying projected finding & development costs and operating costs. The tool is useful for comparing different fiscal regimes in which a company is considering operating and for screening alternative investment prospects.
Emulsion Rheology and Flow Through Unconsolidated Synthetic Porous Media
Authors: Uzoigwe A.C. , Marsden S.S.
Published: December 2007

The flow behavior of emulsions through tubes as well as unconsolidated synthetic porous media is described analytically and verified experimentally.

A correlation technique was developed for the unconsolidated porous medium by coupling the rheological properties of the emulsions, determined from classical viscometric experiments, with the results from porous medium experiments, utilizing the "hydraulic-radius concept" and the Blake-Kozeny-Carman equation. Rheological characterization was carried out with a set of six capillary rheometers and particle size and particle size distribution were determined using a particle size distribution were determined using a Model B Industrial Coulter Counter.

Emulsion qualities (volume per cent of Soltrol in the emulsion) up to and including the 50 per cent quality were found to be Newtonian for the entire range of shear rate and shear stress investigated, (10 sec(-1) to 15,000 sec(-1) and 10 dynes/cm2 to 2500 dynes/cm2, respectively). The 60 and 70 per cent qualities were characterized by Newtonian behavior at low shear values and non-Newtonian pseudoplastic behavior after some critical shear rates and shear stresses, both of which depend on emulsion quality. Fluid slippage at the capillary walls was non-existent, and the rheological characteristics were found to be independent of capillary dimensions.

The theoretical model for the unconsolidated porous medium was tested by comparing the porous medium was tested by comparing the experimental and predicted friction factor-Reynolds number relationship. With forty experimental points, errors in friction factors were found to be 14.6 per cent and 17.4 per cent for the 60 and 70 per cent emulsion qualities, respectively.
The Treatment of Capital in Estimating Fair Market Value of Oil and Gas Properties
Authors: Hartsock James H. , Gruy H. J.
Published: December 2007

Fair market value has its origin in law and is defined as that price that a willing buyer will pay and a willing seller will sell at some point in time, with neither the buyer nor the seller under any compulsion to buy or sell, and both having equal and reasonable bwwledge of the facts. In reality, a perfect sale probably never occurs in which a willing buyer and a willing seller are under no compulsion to buy or sell and both are equally familiar with all the facts. Nonetheless, it is necessary to prepare fair market value estimates for oil and gas properties for the purpose of gift taxes, estate taxes, condemnation cases, mergers and divorce settlements.
Fair Market Value Discount Rates: Analysis of Market Sales Data
Authors: Miller Richard J.
Published: December 2007

The appraisal of oil and gas properties for sale or acquisition; financing; and for estate and ad valorem taxes is dependent on the knowledgeable and appropriate use of Fair Market Value (FMV) discount rates. Information from over 200 FMV property acquisitions in California from 1983 through 1994 has been obtained and evaluated to derive the effective FMV discount rate for each transaction. The analysis of the sales is based on acquisition appraisal data provided by the buyers of the properties.
Effective Exploration and Production Management
Authors: Davidson L. B. , Murthy N. K.
Published: December 2007

This paper describes an approach for effective E&P management based on (1) a methodology for focusing on the most valuable E&P opportunities, and (2) an organization form that is highly effective for managing the chosen opportunities. The approach has produced significant benefits for major oil companies.
Rational Is Practical: Better Evaluations through the Logic of Shareholder Value
Authors: Schuyler J. R.
Published: December 2007

An approach is presented for evaluating corporate project decisions in the context of shareholder value. Properly calculated, project expected monetary value (EMV) represents pre-tax EMV for the investor. Calculating after-tax shareholder value requires, principally, adjusting for tax on distributed project earnings.

Change in the certain equivalent (CE) of an investor's portfolio measures true project value to the investor. The difference between CE and EMV is shown to be minor, especially for marginal projects and when most of the risk is unique to the project. Companies wishing to maximize shareholder value can therefore apply the EMV decision rule, with confidence, as a nearly-optimal decision policy.
Optimising Perforation Performance for the Armada Gas Condensate Development
Authors: Bird K. , Dunmore S.
Published: December 2007

The Armada field development will bring onto production three gas condensate discoveries in Quadrants 16 and 22 of the Central Area of the United Kingdom (UK), North Sea. The largest field, Fleming, will be developed concurrently with the other two deeper reservoirs, Drake and Hawkins. Over one trillion cubic feet of recoverable gas are present. Peak platform production rates of 450 MMscf/d will initially be obtained from eight wells.

The degree of underbalance has a significant impact on well performance and perforation geometry. This paper presents an experimental study to evaluate the effect of underbalance on perforation performance in the Fleming gas-condensate reservoir.

Fleming analogue rock cores were perforated with single shaped charge perforators, and flow tested under simulated downhole conditions. Nitrogen gas was used as the pore fluid for all tests. A brief description of the test facility is included. Cores were taken from outcrop rock chosen to match, as closely as reasonably possible, selected properties of the Fleming reservoir sandstone; in particular, unconfined compressive strength, porosity, permeability, grain size distribution, sorting and shape.

The perforated cores were examined in detail using flow performance comparison, rock mechanical tests, probe permeameter tests, microscopic examination and x-ray scans.

The testing and analysis has enabled:

– A comparison of the effectiveness of underbalances ranging from 200 psi to 2,000 psi based on flow performance using nitrogen gas as the pore fluid. – A comparison of the effectiveness of underbalances ranging from 200 psi to 2,000 psi based on measured perforation geometry. Therefore, a realistic measure of the in-situ perforation geometry. – An analysis of the structure and permeability of the crushed zone around the perforations created when perforating at different underbalances with nitrogen gas in the target rock pores.
Limitations of the Skin Concept and Its Impact on Success Criteria Used in Sand Control
Authors: Unneland Trond , Larsen Leif
Published: December 2007

This paper addresses limitations of the skin concept as a parameter to diagnose and compare well performance and its impact on current success criteria used in sand control. Based on simple models for radial, hemispherical and linear flow, and supported by field examples from high rate gravel packed North Sea oil wells, this paper concludes that the skin concept is in many cases inappropriate in comparisons of inter-well performance. Since well interventions can introduce pressure drops controlled by intrinsic properties of the intervention, independent of formation permeability, it follows that added skin effects can reflect properties of the formation and not of the intervention alone. It is therefore possible that phenomena observed and documented in the petroleum literature concerning well behavior can reflect problems with the methodology instead of problems with the wells.

Limitations of the productivity index (PI) as a parameter to judge well performance are also addressed. Finally, alternative methods are discussed to analyze gravel pack performance and compare completion success.
Scale Inhibitor Adsorption/Desorption vs. Precipitation: The Potential for Extending Squeeze Life While Minimising Formation Damage
Authors: Jordan M. M. , Sorbie K. S. , Griffin P. , Hennessey S. , Hourston K. E. , Waterhouse P.
Published: December 2007

In this paper, results are presented from a series of scale inhibitor core flood experiments using oil reconditioned reservoir cores from four North Sea fields. Phosphonate, poly phosphino carboxylic acid, poly acrylic acid and sulphonated acrylic acid scale inhibitors were used in order to evaluate their performance prior to field squeeze application. Different methods of application were considered including both (i) adsorption/desorption and (ii) precipitation/ redissolution type squeeze treatments. The return profiles for the different types of applications and the different chemistries are compared as are the observed formation damage effects. The advantages and disadvantages are outline for these two mechanism in terms of the extending squeeze lifetime vs potential for formation damage.

It is intend that this paper contributes to the development of better designed and safer field applications of both adsorption and precipitation scale inhibitor squeeze treatments in the light of individual reservoir petrography and petrophysical properties.
The Selection and Application of Loss Control Materials to Minimize Formation Damage in Gravel Packed Completions for a North Sea Field
Authors: Hodge R. M. , MacKinlay W. M. , Landrum W. R.
Published: December 2007

This paper describes a laboratory evaluation of Loss Control Materials (LCM) commonly used to control fluid-loss during completions and workovers and the development of on-site Quality Control procedures for monitoring the performance of the LCM at the well site. In addition to the laboratory results, case histories are provided detailing application of the findings in gravel-packed completions.

Conoco has recently completed five gravel-packed wells in the North Sea. The gravel packs were conducted in two stages: a perforation pre-pack and an annular gravel pack. During this completion procedure, LCM was used to wash excess gravel out of the casing following the pre-pack and to control fluid-loss. Analysis of the first completion indicated production was restricted through the completion. Subsequent evaluation of the completion procedure and LCM products indicated the most likely source of formation damage was residual LCM filter-cake.

Laboratory tests monitoring fluid-loss control, rheology, and formation damage were performed on commonly-used LCM candidates. These candidates included sized-salt formulations, sized-calcium carbonate systems, and polymers from a variety of commercial suppliers. In addition to the evaluation of LCM products, remedial treatment options and a new delayed-release breaker were tested.

Based on test results, an LCM composition using sized-salt, biopolymer, starch, and a slowly-soluble, acid breaker was selected. This composition provided maximum fluid-loss control, maintained adequate rheology, and minimized formation damage in laboratory tests simulating anticipated completion conditions.
Utilization of Biologically Generated Acid for Drilling Fluid Damage Removal and Uniform Acid Placement Across Long Formation Intervals
Authors: Almond Stephen W. , Harris Ralph E. , Penny Glenn S.
Published: December 2007

A method of drilling damage removal is presented which uses biologically generated acid (BGA) as the stimulation fluid. The BGA solution is not reactive during the actual pumping stage which allows its displacement into the reservoir to be controlled by the relatively low permeability of the near wellbore damage. Catalytic generation of acid occurs at a controlled rate once the BGA has been injected into the formation and results in uniform damage removal around the near wellbore region.

The ability of BGA to be generated under a variety of temperature and pressure conditions and the compatibility evaluation of BGA with a variety of commonly used oil and water based drilling muds is first presented to establish some of the operational guidelines for BGA use. Drilling damage removal studies utilizing the modified API linear conductivity flow cell and carbonate material with BGA is presented to demonstrate the effectiveness of this stimulation fluid. Dual core flow test data is then presented which shows BGA's ability and HCL's inability to remove drilling damage over long horizontal intervals in carbonate formations.