bluuebunny/crossref_metadata_2025 huggingface dataset:
Performance Analysis of Horizontal Wells for Underground Gas Storage in Depleted Gas Fields
Authors: Bagci A. Suat , Ozturk Bulent
Published: December 2007

Underground gas storage is a common activitity in countries with major transport and distribution gas pipeline infrastructures, which allows to efficiently resolving demand seasonality problems. The first ever underground gas storage project in Turkey is being carried out in the KM field with injection and withdrawal operations. Optimization of gas storage field was enabled by an improved reservoir and geologic description, including the evaluation of deliverability and storage capacity in the reservoir. Based on available information and those generated by simulation model, KM field is the best candidate for underground gas storage.

The KM offshore natural gas field was discovere in 1988 located about 3 km off the shore of Silivri in the Marmara sea. The field was initially planned to be developed with 3 wells, but recently 2 additional wells were added during the development of the field hence increasing the depletion rate. In this study, after gathering necessary reservoir, fluid, production and pressure data, IMEX (CMG) simulation program was used for history matching of depletion of the field. Reservoir performance after history matching using depletion scenario was predicted and depletion last for 4 years.

In 2005, 5 ERD wells were drilled in KM field from onshore drilling site location for gas storage application. Five scenarios were developed for forecasting of injection and withdrawal performance of the reservoir. These scenarios were used 5 newly drilled horizontal wells with combination of existing vertical wells. With a predetermined injection rate of 65 MMscf/day was set for all the wells and among all scenarios, 5 horizontal – 5 vertical injectors and producers was the most successful in hamdling the gas inventory and he injection period was 5 months and production period was 7 months, respectively. After the determination of the well configuration, the optimum injection rate for the entire field was obtained as 65 MMscf/day by using horizontal gas injection wells. The total produced gas volume until 2012 was estimated as 394 Bscf with this optimum gas injection where the maximum average reservoir pressure was 1901 psi and cushion gas pressure was 1270 psi by withdrawal.
Integrated Reservoir Characterization and Modeling of One Iranian Naturally Fractured Reservoir Using Laboratory and Field Data
Authors: Abdi Yaser , Ghane Mehdi , Haghighi Ahmad Reza
Published: December 2007

This Field is a Cretaceous fractured oil bearing reservoir in the south of Iran composed of tightly packed limestone characterized by high porosity but poor permeability and it is seems to be oil wet. The oil is relatively heavy with API of about 21.3 degrees, viscosity of about 6.85 centipoises and solution GOR of 250-280 scf/stb.

The reservoir energy is limited to fluid expansion and water in flux. The strength of which will be weak because of the low permeability of the rock, as a result the reservoirs are considered to have very poor flow potential. Our studies focused on characterization, modeling and simulation of different production scenarios.

A model was constructed using a three-phase, three-dimensional, dual porosity simulator (ECLIPSE). Because of Existence of uncertainties in SCAL data understanding of two key issues are addressed, Reservoir rock typing and rock wettability. This study emphasized detailed analysis of relevant parameter to these issues which estimated using combination of core, log data and wireline formation tester measurements by developing a numerical model. Several studies were conducted after successfully matching performance of built model with production history of DST results. Eventually the model was applied to run a series of sensitivity simulations for optimization of injector locations, Water injection and gas injection (miscible and immiscible) to increase reservoir oil recovery.

Based on simulation results for different scenarios water injection outperform the others. Miscibility experiments performed in PVTi showed that the minimum miscibility pressure (MMP) is around 12000 psia.

Immiscible gas injection process suffers from unfavorable mobility ratio and high producing GORs, which makes sweep efficiency to decrease and eliminates possibility of ESP usage occurs. This study provides Guidelines for any future development plan in this field.
Analysis of Stress Sensitivity and its Influence on Oil Production from Tight Reservoirs
Authors: Lei Qun , Xiong Wei , Yuan Jiangru , Cui Yuquan , Wu Yu-Shu
Published: December 2007

This paper presents a study of the relationship between permeability and effective stress in tight petroleum reservoir formations. Specifically, a quantitative method is developed to describe the correlation between permeability and effective stress, a method based on the original in situ reservoir effective stress rather than on decreased effective stress during development. The experimental results show that the relationship between intrinsic permeability and effective stress in reservoirs in general follows a quadratic polynomial functional form, found to best capture how effective stress influences formation permeability. In addition, this experimental study reveals that changes in formation permeability, caused by both elastic and plastic deformation, are permanent and irreversible. Related pore-deformation tests using electronic microscope scanning and constant-rate mercury injection techniques show that while stress variation generally has small impact on rock porosity, the size and shape of pore throats have a significant impact on permeability-stress sensitivity. Based on the test results and theoretical analyses, we believe that there exists a cone of pressure depression in the area near production within such stress-sensitive tight reservoirs, leading to a low-permeability zone, and that well production will decrease under the influence of stress sensitivity.
Evaluation of the Results of Gas Storage in a Gas/Condensate Reservoir in the Appalachian Basin
Authors: Aminian K. , Brannon Alan , Ameri S. , Bhavsar A.
Published: December 2007

A gas condensate reservoir in the Appalachian Basin has been converted into a gas storage reservoir. Te results of the first storage cycle are presented. When gas is injected into a depleted gas condensate reservoir, the remaining condensate will evaporate and enrich the injected gas. The degree of mixing among the residue gas, residue liquid, and the injected gas will determine the composition of the gas in the reservoir and the liquid yield at the surface when the gas is withdrawn. The results of the first storage cycle clearly indicated that complete mixing was not achieved in the reservoir. The storage gas compositional changes, due to partial mixing with the native fluids, have both positive and negative impact on the operation of storage field. The lower liquid yields reduce the requirements for liquid handling. However, the heavier hydrocarbons remain in the reservoir longer and the liquid production is extended to a greater number of storage cycles. The liquid yields were low initially because the withdrawn gas had been in the reservoir for a short period of time. Furthermore, this gas did not come into contact with significant liquid due to liquid evaporation. The liquid yields subsequently increased up to a maximum before they declined again. The decline in liquid yields was caused by retrograde condensation in the reservoir. The storage gas compositional changes reduced the storage capacity by 12 percent. The reduction in gas capacity was economically advantageous since it reduced the base gas requirements. Finally, the results of first storage cycles were utilized to optimize the liquid recovery at the surface facilities for the subsequent cycles to prevent liquid drop out by retrograde condensation in the pipeline.
Estimation of Skin Factor By Using Pressure Transient Testing Results of a Single-Rate Well Test
Authors: Gunaydin D. , Mohaghegh S. D. , Gaskari R. , Aminian K.
Published: December 2007

About one-fifth of the natural gas used by Americans each winter comes from natural gas storage sites. Gas storage is the primary means for the gas industry to manage fluctuations in supply and demand. Natural gas can be stored in a variety of ways. Most commonly, it is held in underground formations, in depleted oil or gas reservoirs, or in natural aquifers.

Many gas storage wells show a decline in deliverability as a function of time due to several damage mechanisms. The remedial operations such as stimulation and workovers are used to restore the loss in deliverability and to enhance the productivity of a well.

Candidate selection for the stimulation or workover process is generally based on well history. Skin factor is an important parameter to predict the well performance. Skin is usually calculated from a multi rate well test (MRT). However performing a MRT on a regular basis is an unattractive activity when considering the economic issues. First of all, performing a well test may cause temporary production or injection interruptions. Secondly, the cost associated with well test is considered as an operating expense, a fact that does not help the overall economics of operating a Gas Storage Field. Single Rate tests (SRT) are also performed to estimate the deliverability, but they do not contain sufficient data in order to estimate true skin factor.

The objective of this study is to introduce a new methodology to enhance the current practices of estimating true skin factor from a SRT. This method includes history matching of the actual MRT and then estimation of skin value from SRT using the history matched model. Using this methodology it is shown that change in the skin can be estimated with reasonable accuracy.
The Oriskany Sandstone of Guernsey County, Ohio: A Study of High Surface Treating Pressure Response During Hydraulic Fracturing
Authors: Myers Roger , Martin Jason , Criser Brent
Published: December 2007

According to a publication by J.M. Hall, the "discovery well in 1922 at Cambridge was at a depth of 3,470 feet, which was 1245 feet below the top of the "Big Lime," and gas was encountered with an open flow of 8,000 M, and a rock pressure of 1,150 pounds. By 1925 eleven wells had been completed in this area and the field had started to go to water." Since the 1950s Columbia Gas Transmission Corporation converted 48 of the wells to gas storage1. The EIA lists Guernsey Storage as having a capacity of 7.3 BCF and a maximum daily deliverability of 36.6 MMSCF2.

Around the Appalachian Basin the Oriskany sandstone is known as one of the toughest sands to drill and fracture stimulate. Perhaps, the most extreme example lies under the NW corner of Guernsey County, Ohio (Figure 1). One interesting geological point of interest here is that the Cambridge cross-strike structural discontinuity is located on the western edge of the gas storage field in Guernsey County. The Appalachian Gas Atlas states that there is "no reflection or influence of this basement activity on the Devonian Oriskany."

Figure 1 Arrow points to approximate location of Columbia Gas Transmission Corp's Guernsey Oriskany storage field.

Columbia Gas Transmission Corp, as part of its well reconditioning program, routinely works over some of the wells in this field. Hydraulic fracturing is part of the work-over process to restore lost deliverability. This paper will explore the high surface pressure responses seen during both original frac jobs and refracturing treatments. The fracturing gradients are routinely in excess of the overburden gradient. Interestingly, these same pressures are not experienced in the Silurian age Clinton sandstone that lies below the Oriskany across the field. The treating pressures prompted further investigation to determine their origin and to help improve future stimulation treatment designs. Three- (3) additional wells were to be stimulated this spring in the Guernsey field and their pressure response will be included in this paper.
Pseudo-3D Seismic Use for Development of First US Offshore Gas Storage Facility
Authors: Toelle Brian E. , Kaufman Peter , Chowdhury Nitin , Brown Kenneth G. , Knolle Edmund
Published: December 2007

The North Dauphin Island Gas Field, located in Alabama State waters, was discovered in 1990 by Arco and has produced 64 BCF of gas during its primary production phase. This field was productive from the Dauphin Sand, a Late Miocene sandstone located at an approximate depth of 1,850 feet TVDSS. The field's reservoir has both high porosity and permeability and it has been produced from five boreholes, two near-vertical and three horizontals. One of the near-vertical wells was sidetracked after the original borehole encountered unexpectedly poor reservoir.

In preparation for converting the North Dauphin Island Field and two adjacent smaller Dauphin Sand fields to the first offshore gas storage facility in the US, all available geologic and geophysical data were re-examined. This storage conversion project will result in up to 21 new deviated injection and withdrawal wells being drilled, in addition to several sub-vertical monitoring wells. The targeted reservoir performance for this facility is 50 Bcf high deliverability with injection and withdrawal rates of 1 Bcfd+. Because of the substantial investment required, a complete understanding of the reservoir is vital. The objective of this study was to utilize all available geological and geophysical data to perform a complete reservoir characterization and simulation to determine the optimum design and placement of horizontal injection/withdrawal boreholes and monitoring wells.

During its primary production phase, a set of parallel 2D seismic lines was acquired over much of the field. This data includes 40 towed dual streamer lines, with approximately 300 ft line spacing. Shallow mud gas detrimentally affected some of the seismic signature making normal reservoir characterization of the Dauphin Sand difficult.

As part of this study the original parallel 2D seismic data were re-interpreted using 3D tools and methods. This was accomplished by first loading 40 individual 2D seismic lines as one 3D survey into a geophysical workstation. A shift in the

CDP numbering on some of the lines was necessary to load them as a 3D survey and still maintain a correct special relationship. 3D tools, such as seismic variance and voxel picking, were applied during the interpretation of this pseudo 3D survey. Additionally, the flattening of progressively deeper stratigraphic units proved to be instrumental in obtaining a clearer image of the reservoir. This enhanced interpretation was then used for a more accurate static model and reservoir simulation.
Geomechanical Modeling of a Full Reservoir of the North Sea
Authors: Bourgeois F. , Koutsabeloulis N.
Published: December 2007

A full field study using the geomechanical simulator with a reservoir model was performed to help assess the integrity of the development plan. The study comprised four phases:

Phase I: Enhance the reservoir model. Phase II: Obtain the stress state prior to any operations. Phase III: Perform coupled flow/stress modeling to assess the stress and strain changes induced by production/injection operations up to today. Phase IV: History match the field data using Geomechanics.

Using the graphical pre and post processor VisGen, the reservoir model was extended up to the sea floor. Layers were added on the bottom of the reservoir model to serve as underburden and cells were added on each of the 4 vertical boundaries to serve as the sideburden. Faults and fracture sets were incorporated in the embedded model. The mechanical properties were determined. A stress calibration was determined.

An effective initial stress state was computed that took into account all the complexity of the geomechanical model including contrast in mechanical properties and discontinuity in the rock. The computed initial stress state was in agreement with field data and geological features.

The changes in stress and strain induced by the production/injection operations were assessed using a geomechanical simulator. The computed compaction was in agreement with the estimated value from 4D seismic data. Further, the coupled simulations have demonstrated that compaction and subsidence effects are to be attributed to pore collapse within the reservoir layers and that differential of pore collapse could result in localized well failure.

Finally a coupled fluid flow/stress simulation was performed with dynamic permeability changes according to stress and strain changes. It was established than it was possible to history match the field data based on Geomechanics.

This study demonstrates that geomechanical modeling lends direct support to drilling operations and reservoir management.
Simulation of Vapex Process in Problematic Reservoirs: A Promising Tool Along with Experimental Study
Authors: Rahnema H. , Ghaderi Seyyed M. , Farahani S.
Published: December 2007

Large heavy oil resource presents in reservoirs containing overlying gas cap. However, production from such reservoir is challenging. At the moment there is no proven recovery technique that can be successfully applied to these viscose oil reserves. Recently, vapour extraction process (Vapex) is introduced as an attractive alternative method for such problematic reservoirs.

The objective of this study is to investigate the applicability of Vapex process in reservoirs containing gas cap. This paper is grouped into two parts (i) developing a validated numerical model via experimental data to carry out sensitivity analysis of different parameters which are expensive and difficult to perform on experimental setup (ii) screening study of the Vapex process to real reservoir by using simulation model.

The results show that small gas cap can even be advantageous in this process and improves the recovery by expending the interfacial mass transfer rate and the inter-well communication. In addition, there is a threshold value for the ratio of initial gas to oil volume which beyond that the process loses its efficiency. Moreover, increasing the lateral spacing between the injector and producer is not beneficial in the presence of a small gas cap.
Fluid Flow Properties of Different Carbonate Pore Classes
Authors: Pourmohammadi S. , Hetland S. , Spildo K. , Skauge A.
Published: December 2007

Carbonate reservoirs are usually heterogeneous and may contain rock material from several pore classes. The main pore classes in carbonates are inter- and intraparticle porosity, intercrystalline porosity, mouldic and vuggy material, and also chalk and chalky micro-porosity. The definition of the carbonate pore classes is according to pore structure and petrophysical properties. The proper classification scheme can simplify relationships between carbonate pore types, petrophysical parameters and single phase fluid flow characteristics.

Different petropyhysical parameters such as tortuosity, pore size distribution and dispersivity have been compared for relationship between the petrophysical parameters. A recent pore classification scheme was used to characterize miscible displacement in carbonates with variety of pore types.

Pore system classification for carbonates originated among other from porosity-permeability correlation was found to provide correlations also for other petropyhysical parameters such as pore size distribution, dispersion and tortuosity. These relationships were strongest for pore classes with intergrain porosity.
Characterisation of Vuggy Carbonates
Authors: Vik B. , Djurhuus K. , Spildo K. , Skauge A.
Published: December 2007

Vuggy carbonates are an important pore class for carbonate oil reservoirs. The determination of fluid flow properties like relative permeability from laboratory core floods in not trivial for this heterogeneous type of material. In many cases unusual responses have been observed, showing that several basic assumptions used for the interpretation of laboratory core floods are violated for vuggy material. Since the fluid properties can be attributed to the internal structure of the material it is important to highlight rock characterization. The local vug-matrix heterogeneity and connectivity of vuggs leads also to question about representative elementary volume for petrophysical and fluid flow properties. We focus in this paper on vuggy carbonate rock characterization based on Nuclear Magnetic Resonance (NMR), Micro Computed Tomography (µCT) and Computed Tomography (CT) measurements.

The objectives of the research have been to establish a basis for estimates of fluid flow and oil recovery efficiency in vuggy carbonate rocks.
HWU: An Alternative Approach to Well Repairs/Re-completion in Offshore West Africa–A Case Study With Ghana Saltpond Wells
Authors: Okoronkwo A. , Oham K. , Okoroafor B. , Vhelbherg Ohia P.
Published: December 2007

This paper is a case study of the workover operations initially slated for three Saltpond wells located in the offshore coast of Ghana (Gulf of Guinea). The operation was the first Hydraulic Workover Operation (HWO) offshore West Africa. Hitherto, HWO operations in West Africa (precisely in Nigeria) have been restricted to swamp and land locations for the past five years

Due to the pioneering nature of the project, a lot of challenges were anticipated especially in the area of equipment mobilization, logistics, space management and equipment rig up in an offshore platform. These expectations necessitated a site visit to evaluate prevailing operational conditions on the platform. The information gathered was factored in at the planning stage of the project.

This paper will attempt to review the challenges and cost effectiveness of this project, against the backdrop of utilizing conventional alternatives. It will also highlight the basic facilities required in an offshore platform to make the use of HWU in well repairs/re-completion an alternative and cost saving approach in offshore environments.
Effective and Efficient Management of Niger Delta Conflict: A Precursor to Optimization of Oil and Gas Potentials for Sustainable Development in Nigeria
Authors: Udofia David
Published: December 2007

The lopsided knowledge of conflict by many as being synonymous with war, instability, rancor, hostility, fighting, battle, etc and its associated layman management approaches especially confrontational and avoidance techniques has escalated conflicts in various parts of the world. Consequently, this has deprived majority of the populace from reaping the hidden potentials of conflict.

The Niger Delta region is not exempted from this catastrophe. Ineffective and inefficient management of oil and gas conflicts from 1958 when oil was first discovered in commercial quantity in Oloibiri has escalated conflict from open protest to kidnapping of oil workers. The host and international community are not excluded from these crises due to the importance of ‘black gold’ to man and its spillover effect.

Based on its necessity, and despite negative consequences, Oil multinational companies devised various means for continuous exploration and yet optimizations of its potentials are farfetched due to instability and insecurity in the region.

As apriority, this paper will examine causes, types sources, and roots of conflicts in the region. Equally, contemporary conflict management techniques-third party intervention, joint problem solving etc needed for optimization of oil and gas potentials for sustainable development of Nigeria and mankind in general will operationalized.
An Appraisal of the Global Petroleum Upstream Industry and Its Response to Changes in Crude Oil Prices
Authors: Iledare Omowumi O.
Published: December 2007

This paper presents an appraisal of the global upstream petroleum industry and its responsiveness to changes in crude oil prices from 1980-2006. Temporal and spatial analysis of E&P operational performance indicators suggests that the current estimated worldwide remaining reserves can sustain current worldwide production rate for at least the next four decades, ceteris paribus. Further, the study shows that for every one dollar drop in real crude oil price, 64 drilling rigs were disengaged, on average, from drilling activity globally from 1980-1989; and 50 of these 64 were disengaged in North America. Further, for every one dollar rise in real oil prices from 19992006, 24 and 29 new rigs were engaged in North America and worldwide, respectively. The study shows that global exploration activity responds asymmetrically to rising and declining real oil prices from 1980-2006. The study also shows that the impact of oil prices on global production has significant spatial and intertemporal differences as well.
Use of Thermal Insulation to Prevent Hydrate and Paraffin Wax Deposition
Authors: Owodunni O. L. , Ajienka J. A.
Published: December 2007

Hydrates and paraffin wax deposition are major flow assurance issues of concern in oil and gas production particularly in offshore operations. Thermal insulation is an attractive measure for preventing hydrate and wax deposition.

In this study, a simplified Microsoft Excel Based program was developed for evaluating the effectiveness of thermal insulation in preventing deposition within the tubing when various insulating materials are placed in the tubing-casing annulus as replacement for completion brine. The effects of flowrate and tubing size were also analyzed. The study was performed by modeling steady state and transient heat transfer within the production tubing for both producing and shut-down conditions.

Comparatively, most of the insulation systems considered gave better performance than completion brine. This effect was more significant at low flowrates. It was found that the most effective insulating materials for preventing heat loss and solid deposition during flow conditions do not necessarily possess good insulation characteristics in shut down conditions.

Incorporation of flow assurance issues during completion design can have great impact in reducing incidence of hydrates and paraffin wax deposits.
New Model for Sizing FPSO Vessels Determines Product Availability
Authors: Jones Ogwo Obike Ume , Mbeledogu Ikechukwu Uduezue
Published: December 2007

Deepwater operation and economic constraints demand optimal sizing of Floating Production Storage and Offloading (FPSO) vessels, especially in a hydrocarbon terminalling facility unitisation arrangement where production space economy is critical to operations. A new multi-parameter model is presented for optimal sizing of FPSOs. In the development of the model, a semi-mechanistic approach is used. The model meant for the determination of the optimum gross hull capacity of the FPSO is also applicable to storage tanks in land terminals. A comparative analysis of the existing model and the proposed one is presented. It is shown that the new model has extra capability to explicitly determine product availability under different operating scenarios.

Introduction

Presently, a 2-parameter model in which production space implicitly depends on gross production rate and offtake tanker traffic is available for sizing oil storage terminals. Nevertheless, in a unitized hydrocarbon terminalling facility, optimal tanker size depends principally on how much oil can be made within a loading cycle. Two (2) fields could have the same gross production rate and offtake tanker traffic but different net oil production rate, the rate difference arising from difference in product quality - fluid density and water content. Water draining capability also determines how much oil is available per unit time.

The storage capacity of an FPSO sized based only on gross production and offtake tanker traffic can be significantly less compared with the capacity of the same vessel established with some other design parameters considered, such as drainage facility, number and size of storage compartments, etc. The corrolary is that two vessels of the same deadweight rating and hire-rate could have different storage capacities depending on design parameters. Thus, tanker sizing without reference to product quality and treatment problem would lead to under-/over- sizing of FPSOs or land terminals. Over-estimating the required vessel capacity tends to discourage unitisation of hydrocarbon terminalling facilities because of the limited availability of such large capacity vessels.

This paper presents a new terminal sizing model that considers additional constraints, including fluid properties and dynamics, treatment problems and vessel structural outlay.
Pressure Measurement and Pressure Gradient Analysis: How Reliable for Determining Fluid Density and Compositional Gradients?
Authors: Jackson R. R. , Carnegie A. , Dubost F. X.
Published: December 2007

Pressure-depth plots have been used for over thirty years to evaluate fluid density, fluid contacts, and pressure compartmentalization in formation tester pressure surveys. However in the Niger Delta region and other offshore deepwater environments, many reservoirs are multilayered and highly variable in terms of connectivity, permeability and fluid properties. Such complexity and reservoir heterogeneity means conventional pressure-depth plot and pressure gradient analysis of wireline pressure data is not easy, and identification of in-situ fluid type can be difficult. There is also mounting evidence for the presence of compositional gradients in the hydrocarbon columns of some reservoirs – this raises questions about the conventional approach to pressure gradient analysis and uncertainties in inferring fluid properties and contacts from pressure gradients.

In this contribution using several field examples, we discuss and review formation pressure measurement techniques and data quality, and compare conventional and advanced methods of pressure gradient analysis and fluid contact determination. The interpretation techniques compared include traditional pressure-depth graphical methods, the excess-pressure method and statistical tests. Depth dependent fluid property variation from fluid gradients, PVT properties and EOS-models are compared and discussed. Guidelines are presented on how to interpret wireline pressure measurements in multilayered siliclastic reservoirs, perform connectivity and compositional gradient assessment. We describe how to improve on these interpretations by performing more advanced formation testing procedures; some of which are based upon new and emerging technology.
Using Phased Development as Reservoir Management Technique To Improve Efficiency and Reduce Operational Cost: Ogbotobo Case History
Authors: Ikponmwosa Abu
Published: December 2007

The search for optimal development of a field involves proper knowledge and implementation of Reservoir management techniques. Drawing from the experiences of brown fields in the Southern swamp area, various techniques were identified to optimize the value of a project, aimed at further development of the field; these include phased development, focus on areas of highest potential, implementation of reservoir surveillance, accelerated production, lower operating cost, etc.

Reservoir management is an ongoing continuous cradle-to-grave process, which targets depletion of reservoirs in a way that maximizes recovery and return on investment.

Hydrocarbon was encountered in the Ogbotobo field, between depths of 4755 (X sand) to 8684 (Z sand) ft tvss; however, the major reservoir is the Y (OWCs Ca. 5500 - 5821 ft tvss), which accounts for over 75% of the total field STOIIP.

Production commenced from Ogbotobo in 1998 and to date various drilling campaigns have been carried out to optimize development of the field. So far 14 wells have been drilled in the field, while infill drilling is expected to commence in 2010.

This paper will present how phased development aspect of reservoir management techniques have been applied to maximizing the value of the Ogbotobo field.

The development strategy also include the implementation of an early "production/drilling appraisal" campaign also known as the "parallel engineering" philosophy, where production runs parallel with the design of the permanent facilities, thus improving the economic of the project.
Realising Maximum Value From Closed-in Wells in the Northern Swamp Area of SPDC
Authors: Adenuga O. A. , De Wit A. , Tunde T. O. , Oton E. U. , Ayeni O. , Ofili O.
Published: December 2007

A review of closed-in wells in the Northern Swamp Area (NSA) of The Shell Petroleum Development Company of Nigeria Ltd (SPDC) in 2003 revealed huge opportunities in closed in wells that can be realised at relatively low costs through the application of new technologies. Initial estimates of these opportunities in the Northern Swamp Area (NSA) were about 174 intervals with potential gains of some 53 Mbopd (unrisked) and costs of circa $27 million. A detailed review of these notional candidates was carried out by a multi-disciplinary team. The technically feasible and economically viable rigless (non-rig related) opportunities were matured for execution in 2004. This paper presents results of the rigless activities matured and executed in 2004.

From December 2003 to November 2004, 67 jobs were executed with actual total gains in potential of 44,889 bopd against 34,869 bopd planned. Annual average gains of 20Mbopd were realized from these activities against a plan of 14Mbopd. The jobs were executed at F$13.6 million, and Unit Technical Cost (UTC) of $2.07 per barrel. This project has a Net Present Value (NPV) of F$112 million.

A number of new technologies and cost savings initiatives were implemented during the execution of these activities.
A Unified Model for Diffusion Coefficient Prediction in Non-Ideal Petroleum Fluids
Authors: Leahy-Dios A. , Firoozabadi A.
Published: December 2007

Multicomponent diffusion is important in a variety of applications, including improved oil recovery from CO2 injection in fractured reservoirs, solvent injection in heavy oil reservoirs, and flowline deposition. In order to calculate diffusion flux, molecular diffusion coefficients are required, where fluid non-ideality and the multicomponent nature of the mixture have a significant effect. In this work, we will present a unified model for the calculation of diffusion coefficients of gas and liquid states of multicomponent petroleum fluids. We propose a new model for the binary infinite dilution diffusion coefficients. The generalized Vignes relation is used in multicomponent mixtures. The non-ideality is rigorously described by the fugacity derivatives evaluated by the volume-translated Peng-Robinson equation of state. Predictions for highly non-ideal gas and liquid multicomponent mixtures demonstrate the reliability of the proposed methodology.
Using Production History to Identify Acid Stimulation Candidates in the Spraberry Trend
Authors: Coulthard S. A.
Published: December 2007

There are currently over 10,000 wells producing in the Spraberry field of West Texas. A substantial problem in the maturing field is scale buildup on perforations created by poor reservoir water quality. Spraberry operators matrix acidize wells to remove this buildup and increase production. However, operators lack a proactive method to determine acid stimulation candidates. Currently, wells are not stimulated until scale buildup causes flow to cease entirely. Through the analysis of 32 acidized wells in the Spraberry Driver Unit, this paper defines a stimulation screening method that can proactively increase production in the field. The new production criteria specify that strong stimulation candidates are wells that have produced over 17 BOPD in their history and subsequently have shown sharp production decline rates. Stimulating a well that exhibits these criteria increases the oil production rate by an average of 94%. If only 1% of the 10,000 wells in the Spraberry were acidized, an additional 1.5 MMBbl of oil and $85 million in gross revenue could be recovered.
Neural networks can enhance fuzzy corrosion modeling
Authors: Hajizadeh Yasin
Published: December 2007

Corrosion in the petroleum industry is one the major concerns of the managers and engineers. Both upstream and downstream parts face this problem and the companies spend billions of dollars in this area. To remain competitive with the world market and lead the field, this cost must be kept to a minimum. Therefore there is a high demand for a reliable corrosion prediction model, which could assist our decision making. Deterioration modeling is an essential element for both design and operation of oil and gas systems and will increase the life productivity of company assets

On the other hand in many engineering problems the available information is vague and sometimes measured data or expert knowledge is too imprecise to justify the use of numbers. Fuzzy logic is a good solution here and helps us to compute with words. However the problem is that you can not train the fuzzy systems, so neural networks may be useful here to add learning capability to fuzzy systems.

In this paper the problem of corrosion modeling will be discussed using hybrid neurofuzzy approach. Teaching the fuzzy system with neural networks, and using pressure, temperature, oil and gas production rate, CO2 and H2 S mole percentages of the stream as the model inputs and the corrosion rate as the output, 3-D surfaces for the corrosion rate were obtained and the prediction results of the model which is based on the pattern recognition between input and output parameters is tested. These graphs can be used as a reliable tool in corrosion prediction by managers and engineers.
Application of Nonlinear Dynamics Methods to Study of Relationship Between Seismic Emission and Change of Pore Pressure
Authors: Viktorovich Novikov Alexey
Published: December 2007

In this paper it is proposed to apply methods of nonlinear dynamics to analyzing of microseismic emission data. A porous medium saturated with fluid is considered as multivariate automodel system. The process of microseismic emission is simulated in laboratory conditions and acoustic emission data are obtained from a laboratory experiment. These data are used to establish the fact of attractor existence in the phase space and to calculate correlated attractor dimensions. As a result the deterministic nature of acoustic emission process is established and the number of essential variables describing the system on the asymptotic stage is determined.
Scatter Search Metaheuristic Applied to the History Matching Problem
Authors: de Sousa Sergio Henrique Guerra
Published: December 2007

Reservoir simulation plays an important role in managerial decisions during the life of a reservoir. Thus, it is vital that the simulations present an accurate prospect of real reservoir performance. The main goal of the History Matching (HM) process is to improve the quality of numerical models by contrasting simulated with observed data. A typical HM process evaluates a chosen objective function (OF) comprised by non-linear functions on the uncertain reservoir properties that measure the current mismatch. Thus, the HM problem is a minimization problem where the decision variables are reservoir characterization properties and the goal is to find a set of values for the decision variables that minimize the OF. This paper focuses on the use of an optimization technique called Scatter Search (SS) to perform the HM. The main feature of SS is that it works on a set of solutions called the reference set. The goal is to improve the overall quality of the reference set after each new iteration. New solutions are generated by a non-convex combination of reference solutions.

The proposed methodology was used in both automatic and assisted HM processes and the analyzed reservoir models presented increasing challenges to the algorithm. This paper describes how the HM problem was solved with the SS framework, the expected performance of the methodology in dealing with complex solution spaces and also points how it can be expanded to better scale to a growing number of optimization parameters.

The application of the SS methodology to the HM problem is a recent trend. Unlike most metaheuristics, SS can be effective even when the simulation time of each instance of the problem is long. Most of the current HM methodologies do not perform well when the solution space is both large and complex.
Improvement of Oil Recovery by Jet and Electrical Centrifugal Pumping Technology of Water/Gas Influence
Authors: Telkov Viktor P.
Published: December 2007

Waterflooding is one of the main techniques of oil fields development [1] but this means does not often provide high effectiveness of oil recovery. It comes into particular prominence in the development of high viscosity oil fields when water channels to producing wells and so a great part of oil reserves is not involved in displacement process.

It is known [2, 3] that oil recovery factor can be increased if combined pumping of water and gas is used for oil displacement when the method of water/gas influence is applied. This technique can be used for utilization of associated gas burned in many oil fields the combustion materials of which pollute air.

Nowadays various water/gas influence technologies are known. They are compressor-type technology, uncomressor-type technology, technology using special booster pumps for injecting water/gas mixture (WGM) and technology using jet apparatus. But all these technologies have not gone forward because of their imperfections.
Transient Fluid Flow through Composite Geometries
Authors: de Swaan Abraham
Published: December 2007

The equations describing the transient flow of a fluid with low compresibility through a series of connected porous media with contrasting geometries and/or properties were coupled into one single vector equation. That equation describes pressure and flow velocity at any point in that composite medium and in the Laplace domain. Numerical symmetric transforms are used to obtain solutions in terms of time.

A distinction is made between actual composite geometries in which flow is delimited by actual boundaries in different configurations; and virtual composite geometries, in which flow geometries are observed in pressure plots though no physical boundaries guide the flow.

The formulation was validated through applications to cases presenting composite geometry flow patterns that have been analyzed previously through approaches different from the one presented.

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An Investigation of Pressure Capacity of Rotary Shouldered Connections
Authors: Winship T.E. , Vinson B.
Published: December 2007

Drill pipe tool joints have been in use for many years. The pressure capacity of these joints has not been a major worry until recently. As hydraulic horsepower increased, higher drilling pressures have been tried. The question of pressure capacity keeps arising. This paper presents a theoretical approach to this problem and presents verification of test results obtained in the laboratory. It is now possible to predict pressure capacity of the tool joints when selecting the drill string for the well.

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Rotary Steerable System Improves Reservoir Drilling Efficiency and Wellbore Placement in the Statfjord Field
Authors: Andreassen E. , Blikra H. , Hjelle A. , Kvamme S.A. , Haugen J.
Published: December 2007

Drilling in the Statfjord Field has become increasingly challenging as remaining oil pockets require designer wells, horizontal wells, or Extended Reach Drilling (ERD) wells with great demand for reservoir navigation in three dimensions. Until recently this has been performed with steerable motor assemblies, with frequent steering difficulties in the reservoir sands. Low rate of penetration (ROP) while sliding has given an overall low drilling efficiency, and in some cases inadequate steering ability has resulted in a less than optimum wellbore placement. Long sliding intervals have also resulted in poor hole cleaning, which has contributed to stuck drill string and lost circulation problems.

This paper presents the introduction of a rotary steerable system in the multilateral horizontal well C-23 in the Statfjord Field, and how this improved drilling performance over comparable wells in the reservoir.

The following topics are discussed in the paper:–Field description and brief overview of directional drilling challenges in the Statfjord Field.–Statoil's active role in the development of rotary steerable systems.–Functional description of the rotary steerable system, highlighting the technology's benefits compared to traditional directional drilling methods.–Why well C-23 was chosen as a suitable candidate for therotary steerable system, becoming the first successful utilization of this promising technology in the Norwegian Sector.–Case history, emphasizing directional control, drilling efficiency improvement, and other valuable experiences from utilizing the rotary steerable system.

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Computerized Maintenance Programs: The Drilling Industry Requirements
Authors: Murdoch Ian
Published: December 2007

With the tremendous increase of drilling activity over the last couple of years and the mergers that have occurred, it has become vital that careful consideration be given when choosing computerized software suitable for the Planned Maintenance Program.

The software needs to be simple enough so that Maintenance Personnel are comfortable using the program, and robust enough to operate without software specialist support, particularly when operating on the other side of the globe.

The software has to be flexible enough to encompass the Classification/Certification Societies, Safety Case [D.C.R] and the ever increasing interest being shown by our Customers.

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New Well Design in the Statfjord Field Utilizing a Multi-lateral Well in Low Productive Zones in the Brent Reservoir
Authors: Njaerheim A. , Breivik A.K.H. , Rovde R. , Kvale E. , Kvamme S.A. , Bjoerneli H.M.
Published: December 2007

The value of multi-lateral well technology is increasing for the Statfjord field. This first cased multi-lateral well was drilled from the last vacant slot on the three Statfjord platforms. At the same time, limiting the production decline is increasingly dependent on successful drainage of remaining oil pockets by infill drilling.

This paper presents a case history covering the drilling and completion of the multi-lateral well C-23 on the Statfjord field. The well was drilled with two horizontal branches in the Brent reservoir, 1765 m and 2394 m long respectively. The two horizontal wellbores both penetrate the Talbert and the Ness formation in the same direction, with a distance between each branch of only 80 m. Both laterals have 7" cemented liners in the reservoir. The lateral has been perforated in the Tarbert formation using a snubbing unit.

The following list outlines the main issues that will be described in the paper:–The commercial and technical justification for drilling a multi-lateral well on the Statfjord field and the technical requirements in each lateral.–Key issues in the planning phase.–The importance of establishing a dedicated team together with the service companies covering all disciplines.–The drilling phase, focusing on general well design, well profile, drilling technology (including the use of a rotary steerable system), runing and cementing of 9 5/8" and 7" liners, as well as time schedule.–Design and requirements for the junction at 2376 mMD. Special emphasis will be put on the most critical phases, including the solid whipstock exchange and re-establishing communication to the main bore.–Running and cementing the 2421 m long 7" liner in the lateral, and the use of a proprietary tough cement.–Completion design and production strategy.

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