bluuebunny/crossref_metadata_2025 huggingface dataset:
In-situ Redistribution of Dormant Gas Reservoir Energy to Maximise Oil Recovery
Authors: Boersma Diederik , Deutman Robert , Lau Hon Chung , Wassing Bart
Published: December 2007

This paper discusses a novel development concept of internal gas injection, in which the energy of gas reservoirs is used to maximise production and ultimate recovery of depleted oil reservoirs.

The South West (SW) Ampa Block 11 field in Brunei is characterised by highly stratified formations containing numerous, often areally extensive, stacked thin reservoirs alternated with sealing shales. The sequence contains a variation of oil, gas, oil rim and water reservoirs. Due to faulting and reservoir shale-out, Block 11 oil reservoirs are isolated and therefore lack support from an active aquifer. The pressures in the oil reservoirs have declined severely, resulting in low production rates and a low ultimate recovery (current recovery factors range from 20% to 40% for individual reservoirs).

A novel development concept of internal gas injection is now proposed to provide energy to the oil reservoirs at low unit cost. Block 11 contains gas reservoirs that underlie the more shallow oil reservoirs, and contain an abundance of energy. The internal gas injection scheme will be implemented by drilling two "injection" wells. Within each well-bore gas will be produced from the gas reservoirs and injected directly into the oil reservoirs. The process will be controlled using intelligent well completions. The scheme will substantially increase the oil production rates and reserves. The injected gas will be back-produced both during the proposed development and after economic oil production has ceased, without loss of gas ultimate recovery. The proposed internal gas injection scheme is believed to be an industry first.
Laboratory Studies for Light Oil Air Injection Projects : Potential Application in Handil Field
Authors: Clara Cedric , Durandeau Marc , Quenault Gerard , Nguyen Tuyet-Hang
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Asia Pacific Oil and Gas Conference and Exhibition held in Jakarta, Indonesia, 20–22 April 1999.
Systematic Extensive Laboratory Studies of Microbial EOR Mechanisms and Microbial EOR Application Results in Changqing Oilfield
Authors: Deng Dejun , Li Chenglong , Ju Quanyi , Wu Pingcang , Dietrich F. L. , Zhou Z. H.
Published: December 2007

Microbial EOR was extensively laboratory tested to evaluate microbial affects on fluid properties and oil recovery then successfully applied in Changqing Oilfield. Fourteen different items were evaluated in 271 different tests to better understand the mechanisms of microbial EOR. Testing included core flooding, mobility improvement, crude compositional changes and microbe metabolite production and affects. Results are that the facultative anaerobic microbes can degrade the alkanes in crude into shorter chain alkanes and produce beneficial metabolites including carbon dioxide, surfactants and organic acids. The lower oil viscosity and beneficial metabolites are effective at increasing oil production rate and recovery. The lab testing is very complete and systematic leading to performance evaluation of the treatments in twenty-seven wells. Microbial EOR increased production 17.5 tons/day or eighteen percent.
Effective Evaluation and Development of Sha 1 Igneous reservoir in Shang 741 Area
Authors: Yuan Xiangchun , Wu Wei , Sun Guo , zhao Kailian
Published: December 2007

Sha 1 igneous reservoir in Shang 741 area is located in the western portion of the central uplift zone of Huimin basin, China. Multistage eruptions formed pyroclastic rock and lava, with dolomite and other sedimentary rock interbeds. The igneous rock is characterized by irregular shape and complex pore structure. Only porous igneous rocks and fractured dolomite can be reservoir rock. So, the reservoir is very heterogeneous.

The pre-production evaluation of the igneous reservoirs was performed based on 3D seismic, core analyses, drilling, logging, in especial FMI logging and CMR logging, and production data. The emphases of the research were put on the spatial distribution and internal structure of the igneous, the lithofacies of the igneous rock and sedimentary interbeds, the spatial distribution and quantitative description of pores and fractures, especially the microscopic and macroscopic features of the reservoir rocks, and the prediction of the potential reservoirs. Then, the proved reserves were also estimated. 4 development wells were designed and drilled in favorable oil-bearing area and the expected production were obtained.

This paper discusses the evaluation methods and results of the igneous reservoir in Shang 741 area and its development.
Detection of Communication Cross Faults in Naturally Fractured Reservoirs
Authors: Abdulla Al-Ghamdi , Ershaghi Iraj
Published: December 2007

This paper was prepared for presentation at the 1999 SPE Western Regional Meeting held in Anchorage, Alaska, 23–25 May 1999.
Imbibition Studies of Low-Permeability Porous Media
Authors: Akin S. , Kovscek A. R.
Published: December 2007

A systematic investigation of capillary pressure, relative permeability, and fluid flow characteristics within diatomite (a high porosity, low permeability, siliceous rock) is reported. Using an X-ray computerized tomography (CT) scanner, and a specially constructed imbibition cell, we study spontaneous cocurrent water imbibition into diatomite samples at various initial water saturations. Air-water and oil-water systems are used. Despite a marked difference in rock properties between diatomite and sandstone, including permeability and porosity, we find similar trends in saturation profiles and dimensionless weight gain versus time functions. Diatomite is roughly 100 times less permeable than sandstone, yet it imbibes water at rates rivaling sandstone. Importantly, the spontaneous imbibition data when combined with CT-scan images provides a means to determine dynamic relative permeability and capillary pressure functions.
Using Pressure-While-Drilling Measurements To Solve Extended-Reach Drilling Problems on Alaska's North Slope
Authors: Mallary C. R. , Varco Martin , Quinn D'Arcy
Published: December 2007

Extended-reach drilling (ERD) is playing an important role in the economic development of Alaska's North Slope oil reserves. For some ERD wells, careful well planning and existing drilling practices are sufficient to avoid problems such as wellbore instability, lost circulation and stuck pipe. However, recent Alaskan experience has shown that as well step-outs increase, some operational practices developed on conventional wells are inadequate to successfully deliver cost effective ERD wells. On these wells, careful planning alone cannot always prevent costly drilling problems.

The ability to analyze down hole annular pressures with pressure while drilling (PWD) data has proved invaluable to the drilling engineer. The value of this information is not fully realized, however, until it is put in the hands of the man on the rig who can act on it in real time. This paper examines the impact PWD measurements have made in recent Alaska ERD wells and focuses on both planning and operational uses. Field data are presented from problem and non-problem wells to underscore successful and unsuccessful operational practices. The importance of rig-site training in equivalent circulating density (ECD) management and linkage to drilling, circulating and tripping practices is developed.
The Long-Term Effect of Cyclic Steam on Gravel-Packed Liners
Authors: Hollman G. F. , Tague J. R.
Published: December 2007

Cyclic steam injection is commonly used to improve production in heavy oil fields. The process consists of injecting high temperature steam down the wellbore, and after a soaking period, returning the well to production. In general, high temperature steam improves productivity by decreasing oil viscosity and increasing gravity drainage. However, the same high temperature steam used to improve performance can alter the mineralogy of the gravel-pack materials and near wellbore formation. Recently, a study examining the impact of cyclic steam on the productivity of gravel-pack completions was completed in the West Coalinga field. The study found cyclic steam to be extremely detrimental to the long-term performance of gravel-packed slotted liners due to dissolution and reprecipitation of various minerals found in the gravel-pack materials and localized formation. The conclusions were based on analysis of production profiles of gravel-packed wells undergoing cyclic steam injection and the actual physical inspection of gravel-packed liners cut and pulled from producing wells. Given the results of this study, caution is recommended when considering cyclic steam operations on gravel-packed liners.
Multiphase-Flow Measurement System of High-GOR Applications
Authors: Cellos Harry , Wee Arnstein
Published: December 2007

This paper presents the findings from an installation at Prudhoe Bay which was started up on October 22, 1998. This system consists of a MFI multiphase flow meter, a partial separation separator and a coriolis effect flow meter. The separator is used to widen the operating envelope of the multiphase meter. The control of the separator, data acquisition and final calculations are done by the MFI multiphase flow meter.

Since the system has a very wide operating envelope it can be used on groups of wells with widely divergent flow rates. This particular system is designed for accurate flow measurements with GOR's up to 80 000 scf/bbl and it can handle liquid flow rates in the range 100 – 15 000 bbl/d. The accuracy of the oil flowrate is typical within 5% and the gas flow rate is measured within 1-2 %.

The key element of the system is the MFI multiphase flow meter which is used to measure the multiphase flow in the "liquid leg" of the compact separator. Unlike most well test systems, the measurements of the liquid line are not adversely affected by gas carry under. In fact, it works best with gas flowing in the liquid line.

Operation and control of the system is greatly simplified by the fact that the primary goal of the separator is to remove the liquid from the gas.

The separator is designed to remove down to 5 ppm over the full range of flow rates. The excitation voltage of the coriolis meter is used to detect carryover down to 2-3 ppm. This variable is also used in the control logic and changes the vapor leg flow rate to eliminate carryover.
Optimizing Solvent Allocation in the Prudhoe Bay Miscible Gas Project
Authors: Weaver J. W. , Uldrich D. O.
Published: December 2007

This paper documents the solvent allocation modifications implemented within the Prudhoe Bay Miscible Gas Project (PBMGP) in 1998. These modifications are leading to a more efficient use of the limited miscible injectant (MI) supply by the water alternating gas (WAG) flood.

In 1991, a methodology was implemented in the PBMGP that allocated MI to all of the patterns via a tiered WAG ratio system. The goal was to optimize the use of available MI while controlling the pace of project expansion. Today, the PBMGP is approaching full expansion and currently consists of 149 patterns. The WAG flood now encompasses patterns with a wide range of EOR maturity, expected performance, and operational viability.

Simulation and theoretical analysis indicate that a tiered WAG ratio approach for solvent allocation is no longer optimal. A better method of allocating solvent is a binary system. This involves ranking all patterns in order of efficiency. Each pattern's MI demand is determined by applying a WAG ratio of 1.0 to its current throughput rate. Each pattern is then allocated MI according to its ranking until the MI supply is exhausted. Any remaining patterns are suspended until the next ranking exercise, or until more solvent becomes available.

By design, the binary allocation method redirects MI to the most efficient patterns at the expense of less efficient patterns. To determine each pattern's efficiency, a detailed analysis of field performance data was conducted. This analysis uncovered some patterns that were using MI much less efficiently than others. A number of these performed as if they were immature (implying high efficiency), and otherwise would have been ranked favorably. In reality, they were inefficient due to cement channels, out of zone injection, or poor correlation between injector and producer. These patterns have been suspended from MI injection pending repair.

Implementation of the binary allocation method at Prudhoe Bay is predicted to increase the instantaneous mobilized EOR oil rate between 5,000 and 15,000 stbo/D. The ultimate EOR recovery will increase by 10 to 20 million stb, or 2 – 4% of the original EOR estimate.
A Conceptual Model for Reservoirs Producing from the Monterey Fields, Offshore California
Authors: Ershaghi Iraj , Voskanian Armen
Published: December 2007

Monterey Formation is one of the most productive petroleum-bearing formations in California with substantial proven petroleum reserves both onshore and offshore. A key question in the study of the Monterey Formation is the role of the matrix in terms of its storage of hydrocarbons and its potential contribution to the total ultimate recovery. This issue itself affects the selection of a conceptual model for reservoir studies, resource management, and recovery optimization.

We conducted a study of petrophysical information and performance data from a number of offshore Monterey fields and conditioned our observations with other evidence from published geological studies. All indications are that the most prolific members of the Monterey Formation offshore contributing to well productivity are the brecciated quartz chert intervals (tiger striped chert) with substantial fracture permeability and fracture capacity. The geological processes leading to the formation of the quartz member, geological history of the chert intervals, and study of outcrops indicate that tight chert sections are not serving as pressure support for the fracture as originally thought. As such, the contribution of matrix to recoverable reserves is considered trivial. An interpretative study of the database confirms the existence of a massive network of microfractures communicating with major fractures. Storage capacity of microfractures is a component of the overall recoverable reserves. We have observed similar signals in analysis of core data, well logs, and pressure transient tests data, which confirms our position on this matter.

Diagnostic plots for pressure-time relationship for highly brecciated intervals resemble that of hydraulic fractures intersecting wells. Dual porosity responses observed in certain cases are attributed to the role of microfractures supporting the major fractures.

Drive mechanisms in the offshore Monterey fields are primarily aquifer support and solution gas drive. Communication among wells through the fractures and the aquifer stabilization is seen from interference tests and static pressure measurements.

Water production in certain wells can be excessive because of rapid movement of the oil-water contact (OWC) within the highly permeable fractured intervals.

A bundle of straws draining a tank is proposed as a conceptual model for effective description of the Monterey fields. In this type of a system, for estimating cumulative water influx within the drainage area of individual wells, we have used the X-Plot technique. This methodology allows the application of tank type material balance for aquifer influx calculation.
Innovative Production Enhancement Interventions Through Existing Wellbores
Authors: Hatzignatiou D. G. , Olsen T. N.
Published: December 2007

In the youthful development stages of many hydrocarbon-bearing basins, oil production is prolific, and the primary capital expenditures are primarily for surface facilities and infrastructure. Drilling costs are relatively small by comparison and payback times relatively short. In addition, in offshore environments drilling slots are often limited and at a premium. Therefore, sub par producing intervals are quickly abandoned and sidetracted to make room for new drilling targets with higher oil production potential. Much of this throw away and re-drilling culture still lingers today especially in the offshore industry. However, as the targets become smaller and less prolific, re-drilling may not always be justified as the primary production enhancement solution.

This work presents several production enhancement interventions that can be applied to existing wells to complement re-drilling efforts in a reservoir optimization program. More specifically, results presented address pro-and up-grading marine sequence type of reservoir structures where oil recovery from high mobility layers is usually very efficient, but production rates from the low mobility layers are less than optimum to sometimes minimal. Several industry techniques utilized to date are focused primarily on water shut-off methods at the producing wells, but not much effort is directed in addressing effective means of improving oil recoveries from the remaining less prolific layers. Results presented in this paper provide a variety of such interventions ranging from coiled tubing, hydraulic fracturing, selective zonal isolation-stimulation, sidetracking, etc. which can be applied depending on a given well/reservoir scenario to improve oil recoveries from poorly swept zones and via existing wellbores.
Determination of Production Operation Methods in Pubei Oil Field
Authors: Yang Dao-yong , Zhang Qi , Fan Ling , Bao Bing-sheng , Feng Guo-qiang , Liu Hong-ting
Published: December 2007

As water-alternating-gas (WAG) miscible flooding is the best method to enhance oil recovery for hydrocarbon reservoirs, recently there has been an increasing interest in the WAG processes. In the recent years some reservoirs suitable for miscible flooding have been discovered in the western part of China. The first WAG miscible flooding project, Pubei oil field in Xinjiang, was put into production and scheduled to initially inject miscible gas at the early development stage. One objective of this work is to describe the process of making the optimal field development strategies in this field by integrated technology.

Also presented are theoretical models for comprehensively evaluating and decision-making the oil well production operation methods. These models have been successively applied to thirty reservoirs or fault blocks in China. With consideration of the specialty of the WAG process, the models were developed by incorporating reservoir geologic research, reservoir engineering scheme, reservoir numeric simulation, production performance and surface facility performance. Meanwhile, a novel approach was introduced into the modeling process so that we can simulate the future production performance of oil producers under different conditions in the Pubei oil field.

It is shown that oil producers can maintain stable flowing and there still is potential for the reservoir pressure maintenance, and that gas lift, plunger lift and sucker-rod pumping can be efficient artificial lifting methods under different conditions.
Using New Technology To Overcome Pumping Problems in Horizontal Wells
Authors: Evans B. L. , Muth G. M.
Published: December 2007

Increasingly, horizontal wells are being used in the development of oil fields. The benefits have been shown to outweigh the additional costs in many fields. As could be expected, horizontal wells are experiencing the usual pumping problems (such as sanding) as those seen in vertical wells. In addition, deviated holes can cause additional rod and tubing wear and increased loads. The higher costs of horizontal wells and higher oil production rates create more urgency that the problems be overcome as quickly and economically as possible. The use of a downhole conversion kit allows the modification of the pumping system to a dual string system (a "power string" and a "production string"). This new system has been shown to be very effective in overcoming or mitigating the pumping problems of horizontal wells. The conversion kit can be used with insert, tubing or PCP pumps. In addition, the downhole assembly can allow the running of temperature and other surveys without the removal of any downhole equipment. This feature is especially helpful in steam injection projects.
Formation Damage Associated with Water-Based Drilling Fluids and Emulsified Acid Study
Authors: Lynn J.D. , Nasr-El-Din H.A.
Published: December 2007

Water-based fluids are used for drilling most of vertical and horizontal wells in carbonate reservoirs in Saudi Arabia. Even in moderate and lower permeability formations, drilling solids can invade the formation and cause fines plugging. An XC-polymer based drilling fluid, containing sized calcium carbonate particles (marble), is used to limit the amount of fluids lost to the formation during the drilling operations. However, near wellbore damage was evident from field tests conducted on several vertical wells. High skin factors (+2 to +4) following drilling indicated severe well damage and decreased production potential. The only solutions are drilling additional wells to increase production capacity, or stimulation of existing damaged wells. A stimulation procedure was needed to mitigate the problem.

Traditional stimulation efforts in carbonate reservoirs are conducted using regular HCl acid. Rock mechanical studies have indicated wellbore stability after drilling, and rock strength are concerns in the subject formations. It was suspected that an attempt at normal HCl acid matrix stimulation would result in surface washout and enlargement of the wellbore. This is especially true in low permeability (less than 30 mD), fine grain carbonates. This could exacerbate borehole stability problems.

Emulsified acids have been shown to induce deep wormholes in carbonates. These wormholes will serve the same function as perforations to by-pass the drilling damage, yet maintain the integrity of the formation. An emulsified 15 wt. percent HCl - diesel mixture (at 70:30 volume ratio) was evaluated as a portion of an ongoing study of the effects of acid stimulation in carbonate reservoirs.

Currently, there are few accurate methods of laboratory evaluation of this type of stimulation fluid, and scale up-factors are nebulous at best. Traditional tables for matrix type stimulation are inaccurate, and result in excessive acid volumes. Acidizing with large acid volumes is not recommended because of the weak nature of the rock in some fields.

This paper demonstrates a new laboratory core test procedure and provides a novel interpretation of scale-up equations developed for the study. The resulting laboratory data are compared to field results, and show:

1. The test procedure accurately simulates the damaged seen in the formation.

2. The acid can effectively stimulate the formation, while preserving the formation integrity.

3. The acid penetration and “worm-hole wander” can be controlled by monitoring acid injection rate and volume.

4. The scale-up volume equations to be accurate for emulsified acid treatments.
Gravel-pack damage removal in horizontal and vertical wells
Authors: Kotlar H. K. , Thomas R. , Ziauddin M. , Brydon H. , Karlstad S.
Published: December 2007

Gravel-packs can be damaged by a variety of mechanisms which include scale formation, fines migration, paraffin and asphaltene deposition resulting in a damage skin of 10-300. Frequently damage removal treatments do not remove this damage completely from all the producing zones, resulting in a short treatment life and/or inadequate production. This can be attributed to poor diversion and/or improper damage characterization. This paper focuses on several aspects of improved damage removal in gravel-packed wells. A methodology to assist in the proper identification of the damage mechanism and the design process for more effective treatments is presented. An integrated approach using an overall systems analysis coupled with log, water analysis and numerical simulations of the gravel-pack/matrix damage removal is recommended.

A numerical model to simulate acid treatments of gravelpacked well is presented and used to evaluate several treatments performed on wells from the Gullfaks field in the North Sea. Results indicated greater than 75% of the damage is in the gravel pack. The model incorporates a detailed wellbore model integrated with a reservoir mode for simulation of acidizing treatments in horizontal and vertical gravel-packed wells. An algorithm for quantifying the damage in the gravelpack is discussed in detail. Various diversion techniques and fluid formulations are evaluated using the simulator and compared to field results with emphasis on pre and posttreatment production logs.

The results of this study helped us establish guidelines for identifying the damage mechanism and in designing optimal treatments for matrix stimulation of gravel-packed wells.
Candidate and Chemical Selection Rules for Water Shutoff Polymer Treatments
Authors: Mennella Aniello , Chiappa Luisa , Lockhart Thomas P. , Burrafato Giovanni
Published: December 2007

Water shutoff treatments with polymers that selectively reduce the water permeability can be effective to reduce water production from hydrocarbon wells that cannot be treated with conventional approaches. In this paper we present an analysis that starts from the principal operative questions and defines the main physical-chemical issues to be understood in order to develop a reliable technology. These issues are discussed by showing results from a number of experimental and simulation studies conducted in our laboratories with the goal to link the understanding of basic mechanisms to the development of operational rules. This work shows the elaboration of understanding-based rules for candidate and chemical selection to be an effective strategy for the application of this technology in the field.
Investigation of Proppant-Pack Formation Interface and Relationship to Particulate Invasion
Authors: Weaver Jim , Blauch Matt , Parker Mark , Todd Brad
Published: December 2007

Many wells completed in soft, poorly consolidated formations tend to underperform relative to the reservoir's production potential. Steep production declines are also indicative of problems with the reservoir. These problems are often attributed to poor drilling and completion practices. Formation-incompatible fluids can be lost to the formation, resulting in significant nearwell permeability loss. Advances in soft-rock stimulation technology have made frac-packing the preferred method for bypassing damaged regions within the formation and for optimizing access to productive zones. Because many soft formations produce fines that can invade the proppant pack and lower productivity, choosing the optimal proppant size for such operations is paramount to overall production-enhancement success.

Numerous studies describe the optimization of proppant size as means of minimizing fines invasion and maximizing pack conductivity. This paper examines other mechanisms that affect pack conductivity and the prevention of fines invasion and migration. The results of this study provide a greater understanding of proppant-pack damage mechanisms and present evidence that proppant coated with chemical agents that make the proppant surfaces "tacky" can significantly improve fracture conductivity.

Microscopic observations of the proppant-pack/formation interface were performed with a dynamic flow model. Images taken from this model indicate that several parameters, such as particle surface charge, wettability, and proppant tackiness, greatly influence fines migration into a proppant pack, regardless of the proppant sizing criteria used. API conductivity measurements performed with realistic pressures, closure stresses, and flow rates were used to confirm micromodel observations.

This procedure provided a quantitative measure of the effects of size criteria and proppant tackiness on fracture conductivity. Fines invasion beyond the proppant-pack/formation interface was determined through postmeasurement microscopic examinations.

The effect of proppant tackifiers on the proppant-pack/ formation interface was also examined, resulting in significant changes in proppant-sizing criteria for frac-packing operations. These findings should have a significant impact on future frac-pack designs.
Enhancing Liquid Lift From Low Pressure Gas Reservoirs
Authors: Yamamoto Hiro , Christiansen Richard L.
Published: December 2007

Liquid loading in low production gas wells is a nuisance for production engineers in the natural gas industry. It is essential to maintain gas wells free of liquid; otherwise, the production will be severely reduced by backpressure of the accumulated liquids, and by reduced gas relative permeability in the surrounding formation.

The most fundamental solution for the liquid loading problem is to select tubing diameter for the well such that the natural energy in the reservoir will give a gas velocity sufficient to lift liquids from the sand face of the reservoir to the surface. Unfortunately, the optimum diameter varies for different periods in the life of a well.

Here, a new approach to the liquid loading problem is reported. By introducing restrictions, such as orifices, inside the tubing to alter flow mechanisms, liquid may be lifted by gas flow rates below the conventionally accepted critical rate. Extensive laboratory experiments with a 40-foot-tall flow loop with 1.5-inch-inside-diameter tubing were conducted to test the effect of five different designs of restrictions. In these experiments, the effects of gas flow rate, of restriction design, of flow loop inclination, and of design of the outlet at the top of the loop were considered. The experiments proved that the restrictions alter two-phase flow behavior and improve liquid lifting rate in the flow loop.
Estimating Productivity Using Petrophysical Data: Second Frontier Formation, Lincoln County, Wyoming
Authors: Link Michael A. , Stonecipher Sharon A. , Watson Robert W.
Published: December 2007

The Second Frontier Formation in the Emigrant Springs area is a moderately tight, gas producing sandstone reservoir with absolute permeabilities averaging less than 1.0 md. Well completion in the area involves setting casing through the zone, perforation of the casing, and stimulation by hydrofracturing. Well evaluation is typically accomplished using production history and decline curves. Further development in the area, in terms of step-outs and infill drilling, demands techniques for predicting well productivity using wireline log data obtained prior to the setting of the casing.

In an effort to quantify these values, a petrophysical analysis was performed. Open-hole well logs, sidewall cores, and specialized logs such as Combinable Magnetic Resonance (CMR) and Formation Multi Imager (FMI) were used to compute parameters such as effective porosity, water saturation and permeability. The relationships between these parameters and productivity indicators, such as initial production (IP) and estimated ultimate recovery (EUR), were then studied.

Furthermore, this analysis included a review of depositional environments in the area to identify any effects on production. This examination included petrographic analysis of drill cuttings, and the interpretation of FMI logs, which were then coupled to previous petrographic work that considered similar data from the same general area1.

Results indicate that the product of log-derived porosity, permeability, gas saturation and pay thickness are indicators of IP and EUR. Additionally, this analysis demonstrates that productivity indicators are strongly influenced by geometric, textural, and diagenetic characteristics of the reservoir rock (lithofacies) that are largely a function of depositional environment.
The Multiple Role of Unconventional Drilling Technologies. From Well Design to Well Productivity
Authors: Charlez Ph. A. , Bréant P.
Published: December 2007

This paper deals with new drilling technologies and is focused on their ability to reduce capital expenditure per barrel produced. During the last decade, they have greatly contributed both to improve production and reserves but also to decrease operational costs. TOTAL has been involved in these unconventional technologies all over the world and has used them for numerous original applications ERD to reach offshore reserves from onshore facilities (Argentina),ERD to test a marginal panel from existing offshore facilities (North Sea),Multilaterals to explore and delineate a blind zone (Libya), to improve production and to increase reserves (Libya, North Sea) or to revitalise a mature field (Middle East).

Unconventional drilling technologies play a key role today where conventional technologies are not fully efficient to keep development profitable. With time, smart drilling which appeared at the end of the 80’s has progressively become a must for any field development.
Application of the Diagnostic Plot Using a Derivative Based on Shut-In Time
Authors: Spivey John P. , Lee W. John
Published: December 2007

The conventional log-log diagnostic plot with pressure change and derivative with respect to the superposition time function has been applied with tremendous success in diagnosis of reservoir behavior by giving the buildup pressure response a shape similar to that of the drawdown response for a wide variety of different boundary conditions. However, this very success has led in a number of cases to overconfidence in its applicability and interpretation using an inappropriate reservoir model.

This paper discusses the use of a diagnostic plot comprising the pressure change and pressure derivative calculated with respect to, and graphed vs., shutin time. This form of the diagnostic plot requires a catalog of buildup pressure responses for different reservoir geometries and different producing times. This paper provides such a catalog for several common reservoir geometries.

Three field examples illustrating the application of the diagnostic plot using the derivative vs. shutin time are presented.
Water Induced Compaction in the Ekofisk Field
Authors: Sylte J. E. , Thomas L. K. , Rhett D. W. , Bruning D. D. , Nagel N. B.
Published: December 2007

Over 7.8 meters of seafloor subsidence has occurred at the Ekofisk Field in the Norwegian sector of the North Sea since the start of production in 1971. Full field water injection was initiated at Ekofisk on a limited scale in 1987. The surface subsidence is a result of reservoir compaction, which is considered primarily to be due to pressure depletion until the early 1990's and water weakening thereafter. Rock compressibility was input as a function of initial porosity and increasing net effective stress (i.e. declining reservoir pressure) in earlier Ekofisk studies. In 1994, under a voidage balancing reservoir management program, water injection was increased sufficiently to stabilize reservoir pressure. However, no reduction in surface subsidence rate was seen. This, in combination with other field and lab observations, led to the conclusion that water was weakening the reservoir chalk and necessitated revising the rock compressibility functions at Ekofisk to include the effect of additional compaction due to the water weakening.

The development and implementation of the water induced compaction functions at Ekofisk is presented in this paper. Rock compressibility is now input into the model as a function of initial porosity, net effective stress, and water saturation. As water saturation increases in a model cell due to water injection or water influx, the model cell transitions to a weaker stress-strain curve. The effect of increasing water saturation, and the resulting water weakening of the chalk, is that compaction and subsidence may continue in spite of stable or increasing reservoir pressure. Both laboratory and field data are presented which support the use of the water weakening functions. The development and calibration of these curves is presented, which includes the effects of fracturing, creep, water dispersion effects, hysteresis logic, and strain hardening. A comparison of the calculated and measured compaction and subsidence bowls is also presented.
Applications of Neural Networks in Multiwell Field Development
Authors: Centilmen A. , Ertekin T. , Grader A. S.
Published: December 2007

A common field development task is the optimal placement of the wells. One of the key parameters in the success of a new well is its physical location in the reservoir. When several wells are planned hundreds even thousands of placement combinations must be considered in order to optimize specific production goals. The large number of degrees of freedom makes using a standard reservoir simulator to evaluate all these placement combinations prohibitively time consuming and expensive. This paper demonstrates a neuro-simulation technique that forms a bridge between an accurate reservoir simulator and a fully-trained predictive artificial neural network (ANN). The paper outlines how the coupling of soft and hard computing techniques allows for a rapid and efficient selection of well locations while maintaining reasonable accuracy. In this method, several key well scenarios are selected by engineering judgement and/or randomly. These scenarios are then evaluated using a numerical reservoir simulator. The simulation results form the basis for training an ANN. When the ANN is trained for a specific reservoir configuration, it forms a fast predictive tool for optimizing the locations of the new wells in the reservoir. Thousands of possible scenarios are evaluated using the ANN with an insignificant computational effort. Then, all the predictions are ranked and sorted to provide the best possible scenario for placing the new wells. It is the combination between ANN and genetic concepts that leads to an efficient optimization process. Simulated reservoir examples with various shapes, properties, and number of existing new wells are considered in the paper. The results of the paper demonstrate the effectiveness of neuro-simulation by reducing the computational effort and maintaining accurate predictive capabilities. The paper also presents the guidelines for using neuro-simulation to optimize the placement of the wells.
Reliable Electronics for High-Temperature Downhole Applications
Authors: Gingerich B. L. , Brusius P. G. , Maclean I. M.
Published: December 2007

This paper outlines the reliability improvements which can be made to down hole systems by a line of reliable high temperature electronics which have been developed for instrumentation and distributed controls on aircraft gas turbine engines. Testing of these components has shown long life capability of 5 years or more at temperatures up to 225°C. These same components form the electronics base for a data acquisition system that can be used in downhole permanent gauges installed during completion. As part of an ongoing effort to provide reliable high temperature electronics a statistical database has been developed to project failure rates for these components
Development of Remote-Controlled Dynamic Orientating System
Authors: Urayama T. , Yonezawa T. , Nakahara A. , Ikeda A. , Nakayama T. , Gleitman D. D.
Published: December 2007

Obtaining a smoother well bore path and reducing of drilling costs, through higher penetration rate and reduced trip frequency, are essential objectives of a technical innovation for horizontal and directional well drilling. In order to achieve these goals, a research project developing a remote controlled dynamic orientating system (RCDOS) for horizontal well drilling was organized and initiated by Japan National Oil Corporation (JNOC) in 1989. Originally, the project was composed of developing two sub-systems, a new deflection actuator and a new two-way telemetry system with a high bit rate. As the former could be used in combination with practical conventional mud pulse telemetry systems, it has lately become an independent target in the project. The deflection actuator is installed above a bit. The bending angle and bit tool face can be controlled independently and dynamically during the drilling process by the deflection actuator, from 0 to 1.5 degrees and 0 to 360 degrees respectively. Both tools for 8-1/2 and 12-1/4 inch bore holes have been developed. The deflection actuator is applicable for both rotary steerable and motor steerable drilling tools, and it consists of the following main components: communication terminal, seal mechanisms, pressure compensator, electromagnetic connector, reference stabilizer, high side sensor, RCDOS controller and bit drive-shaft bias unit. The bias unit is structured with Oldham couplings, electromagnetic clutches, positioning sensors for rotation angle detection, harmonic drive gears and double eccentric rings. It is a unique system for a drilling tool, because of its simple design principal and excellent performance. The RCDOS deflection actuator is the foundation of a new rotary steerable drilling tool currently under development (subject of future technical publications). In this paper, the fundamental work carried out for developing the RCDOS deflection actuator and verifying its performance is presented.
Engineering and Economical Concerns on Cost Recovery Treatment for Sharing Production Facilities
Authors: Shaheen S. E. , Bakr M. , EL-Menyawy M.
Published: December 2007

Some oil / Gas fields are considered marginal and not economically exploitable under the approach of stand alone project. Therefore, sharing production facilities with other concessionaire shall considerably reduce capital and operating costs.

Nearby facilities can be utilized to process and accommodate the production of such marginal fields. The economical concerns of cost recovery treatment for the capital investments of the production facilities, versus operating expenses is vital in the development decision For marginal discoveries.

Development of oil fields depends on the expected revenue from such fields. This revenue depends mainly on; proven recoverable reserves, oil price and expenses. This is in addition to the applied legislations and agreements controlling the investors cost recovery and profitability. The utilization fee is subjected to a different cost recovery treatment according to the following: No capital investments are required (existing facilities)Sharing the cost of Constructing new facilities as a new asset.

The combination of the capital / operating fee is successfully applied in Egypt, where both owner(s) and user(s) are sharing the benefit of this methodology. The application of the above methodology is discussed in the paper, with special.emphases on the encountered problems and the reached solutions. Real field data and economical concerns are discussed in the paper for each of the following "sharing facilities" examples: Sharing pipeline network: Western pipelineSouthern pipelineMediterranean shore pipelineMain gas trunk pipelineThird party area at the Gulf of Suez.Sharing facilities in the Eastern Desert.Sharing facilities in the Western Desert.Sharing EI-Hamra terminal facilities.

The objective is not only to convert a non profitable project into profitable one, but also to maximize such profits, for the mutual benefits of both owners and users.
Prediction of Slug Frequency for Gas-Liquid Flows
Authors: Zabaras G. J.
Published: December 2007

During slug flow, knowledge of the slug frequency is essential for the gas -liquid receiving facility design as well as for predicting various slug flow characteristics such as slug length and pressure drop.

Various methods proposed in the literature for predicting the slugging frequency in horizontal and inclined pipes were examined. These included both empirical correlations as well as mechanistic models. Slug flow frequency data taken with an air-water system in a laboratory flow loop together with data from the published literature were compared to the predictions of the various methods. A total of 399 data points were collected covering pipe diameters from 1 to 8 inches and inclinations from 0 to 11 degrees above the horizontal. A total of eight published methods were compared to the data but none was found satisfactory. For this reason, the mechanistic slug frequency model of Taitel and Dukler (1976) was investigated in detail as an alternative unbiased prediction method. This model required the solution of the unsteady-state equations for mass and momentum by a finite difference technique. This numerical model gave satisfactory results at the expense of considerable computer CPU time. For faster slug frequency calculations a new correlation was developed utilizing all 399 data points. This resulted in 0% average error (bias) and 60% average absolute error. This correlation represents a significant improvement in slug frequency prediction accuracy over the other methods studied.
Multiphase Pumping for Heavy Oil: Results of a Field Test Campaign
Authors: Giuggioli A. , Villa M. , De Ghetto G. , Colombi P.
Published: December 2007

The paper describes the behaviour of a multiphase pump prototype installed in a heavy oil field of Eni -Agip in Sicily. The location is onshore, at the end of a 30 km. long pipeline connecting the production offshore platforms of Prezioso and Perla to the onshore oil process plant of Gela.

Main fluidodynamic features of the test site are: oil density 18° API, GOR = 120 Scf / bbl, Q liquid = 2500 bbl / day, W.C. = 10%. The dead oil viscosity at ambient temperature (17° C) is about 700 cP.

The prototype is based on the twin screw technology and has the following main features: -electric power;400 kW-nominal multiphase flowrate;18.000 bbl / day-fluid maximum allowable viscosity;1200 cP-maximum differential pressure;40 bars

In order to allow different flow conditions (pressure, temperature, flowrates, viscosity, void fractions) some auxiliary equipment were installed with the multiphase pump: an interconnecting skid, interposed between the pump and the production plant of Gela oil centre.a booster pump connected with the liquid outlet of the production separator and the interconnecting skid.

The tests were run at different heads, in the range between 10 and 33 bars, simulated by a choke valve in the interconnecting skid downstream the pump. The aspiration pressure was 3 bar.

The main problems encountered during the experimentation were related with the high paraffin content of the oil. The problem was sorted out substituting the fine mesh filter with a larger one.

The field tests ran for about 10 months with a record of 6400 running hours without any major problem. The main conclusion of experimentation is that multiphase pump is quite robust and reliable machine ready for industrial application even with heavy oils with viscosity up to 1200 cP, and void fraction up to 90-95%.