bluuebunny/crossref_metadata_2025 huggingface dataset:
Modeling and Validation of Hindered-Matrix-Fracture Transfer for Naturally Fractured Petroleum Reservoirs
Authors: Civan Faruk , Rasmussen Maurice L.
Published: December 2007

This paper presents the formulation, validation, and application of the improved matrix-fracture-transfer models for naturally fractured reservoirs based on presumed matrix block shapes. These models are derived for applications to primary oil and gas production by pressure depression and secondary oil production by water flooding of oil reservoirs by considering hindered-fluid transfer between matrix blocks and the surrounding natural fractures. The analytical solutions derived for special boundary conditions involving the typical laboratory tests using rectangular and cylindrical shape rock samples to represent the matrix blocks are verified with experimental data and the values of the characteristic parameters, such as the diffusion coefficient and skin coefficient and thickness, are determined.

The analytical models, workable equations, and straight- line data plotting schemes developed in this paper can be utilized for effective analysis and interpretation of laboratory experimental data using various shape reservoir rock samples. This allows for rapid determination of the characteristic parameters of the matrix-fracture transfer models for various shape matrix blocks, which are essential for prediction of oil recovery from naturally fractured reservoirs undergoing a water flooding process by means of a computer simulation. Although no confirmation was presented for single-phase oil or gas production by pressure depression because of the lack of experimental data, similar results are expected to hold by the present workable equations, because the single-phase flow description can be expressed in terms of the same dimensionless form as the two-phase flow description. Further, the single-phase flow description is more accurate than the two-phase flow description, because the latter has been approximated based on the constant-average capillary- diffusion coefficient assumptions to derive analytical solutions.
Producing The Well In Artificial Lift By a Subsurface Compensated Pump: A New Production Method
Authors: Buchman Smil S.
Published: December 2007

Introduction

This paper presents a new production method in which the reservoir energy spent to lift the production from perforation-depth to the dynamic liquid level is replaced by surface energy, and consequently the well daily rate and cumulative production is increased by 200 - 250 %. The method can be used in any well at any time.

The paper is based on the analysis of how the reservoir energy generated by the expansion of the reservoir fluids is used to produce the well:

PROFITABLE USAGE: Moves the production through the pay zone into the well bore.

WASTEFUL USAGE: Sends the reservoir energy to:Overcome the liquid friction along the production flow path.Lift the production from perforation-depth to the dynamic liquid level.

Present production practice recognizes and reduces only the reservoir energy wasted to overcome the liquid friction through the pay zone by using better and cleaner perforations, acidizing, fracturing, and other techniques. When less reservoir energy is used to overcome the frictions through the pay zone, the well performance, in both rate and cumulative production, is increased.

To date all artificial lifting methods are spending surface energy only to lift the production from the dynamic liquid level to the surface. However, the energy needed to lift the production from perforation-depth to the dynamic liquid level, the largest waste of reservoir energy, is now overlooked and has not been recognized as the most important way to significantly increase well performance. The proposed new production method substitutes the reservoir energy by surface energy in order to lift the production from perforation-depth to the dynamic liquid level. Accordingly the well performance in day rate and cumulative production is increased by 200 - 250 % compared to the actual well performance.

The quickest and easiest way to produce the well according to the new production method, is to run a subsurface compensated plunger pump assembled from the API Spec-11AX parts, and work with the same beam pump. A subsurface compensated pump, is a liquid lifting device, which can not be drawn by the well pressure.
How to Maintain High Producing Efficiency in Sucker Rod Lift Operations
Authors: McCoy J. N. , Rowlan O. L. , Becker D. J. , Podio A. L.
Published: December 2007

Throughout the world the most commonly used method to artificially produce wells is by sucker rod lift. Low producing efficiency caused by incomplete pump fillage is the most common operational problem experienced by sucker rod lifted wells. Incomplete pump fillage is the result of having a pump capacity that exceeds the production rate of the well or having poor gas separation at the pump intake with a portion of the pump displacement being lost to gas interference. More efficient operations and lower cost will result, if these wells are operated with the pump filled with liquid by eliminating any gas interference in the pump and controlling pump run time so the pump displacement will match the inflow of liquid from the reservoir into the wellbore. The operator must monitor well to insure that the pump has no mechanical problems and efficient operations are maintained as all the available liquid is produced from the wellbore.
Advances in Horizontal-Oriented Perforating Optimize Perforation Efficiency and Production While Maintaining Borehole Stability
Authors: Benavides Simon P. , Myers William D. , Van Sickle Edgar W. , Vargervik Kristian
Published: December 2007

A major operator in the North Sea put one of their fields on stream in the autumn of 1988. Since then, over 1.7 billion barrels of oil have been produced, reaching a peak of more than 500,000 BOPD. Today, an estimated 0.9 billion barrels of oil remain to be recovered from the field; however, production has fallen to less than 400,000 BOPD and the operator is facing tremendous challenges to increase production.

New technologies, such as horizontal drilling and horizontal oriented perforating have helped increase production. Drilling in a water depth of 109 m of water, the operator wanted to optimize production from a 2246-m horizontal well section by reducing the risk of future sand production and selecting the most effective perforation coverage.

Perforating in highly deviated or horizontal wells presents any service company with a serious technical challenge. Attempting to maintain wellbore and perforation tunnel stability by perforating in the direction of maximum stress compounds the complexity of the perforating job. Ensuring that orientation remains valid while navigating through severe doglegs requires detailed pre-job design planning supported by applicable research data.

This paper discusses advances in horizontal oriented perforating in long horizontal sections designed to optimize perforation efficiency and production. The techniques and results discussed are applicable to any horizontal or highly deviated well where orientation of charges to maintain wellbore stability is critical. New developments to navigate through severe doglegs and maintain orientation are significant contributions to perforation technology. Some of the results and experiences encountered while performing an oriented perforating job in a 2246-m horizontal section of the North Sea well are also discussed in this paper. A world record was set by perforating a net of 1496 m of the horizontal section in a single trip with orientation successfully verified. Additional discussion on the testing and research that preceded the job is presented.

As demonstrated in positive results from the North Sea well, perforating with oriented charges in horizontal sections will play a key role in the future to assist operators increase and optimize production from new or declining fields.
Characterization of Slug Flow in Horizontal and Inclined Pipes
Authors: Bagci S. , Al-Shareef A.
Published: December 2007

Two-phase flow in horizontal and inclined pipelines can cause significant practical operating problems. When slugs flow in a horizontal pipeline that contains sections of different inclinations they undergo a change of length and slug flow characteristics as the slug move from section to section. In addition, slugs can be generated at low elbows, dissipate at top elbows and shrink or grow in length as they travel along the pipe.

A mathematical model and a computer program were developed to simulate these phenomena. The model was based on the sink/source concept at the pipeline connections. A connection between two pipeline sections of different slopes was conveniently called elbow. An elbow accumulates liquid as a sink, and releases liquid as a source. The sink/source has a characteristic capacity of its own. This capacity is positive if the liquid can indeed be accumulated at the elbow or negative if the liquid is actually drained away from the elbow. This type of treatment effectively isolates the flow upstream from an elbow from that downstream, while still allowing flow interactions between two detailed pipeline sections. The hydrodynamic flow model was also used to calculate the film liquid holdup in horizontal and inclined pipelines. The model can successfully predict the liquid film holdup if the liquid film height is assumed to be uniform through the gas pocket. Many other models were used to calculate all the needed parameters to perform the sink/source model.

The overall effect of horizontal and inclined pipelines on slug flow depends on the operating flow rates and pipeline configurations. For special case of near constant slug frequency corresponding to moderately high superficial liquid and gas velocities, this effect was found to be small. The changes in the film characteristics between two adjacent pipeline sections were found to be mostly responsible for the pseudo-slug generation, slug growth and dissipation in the downstream pipeline sections. The film liquid holdup decreased with increasing pipe diameter. The unit slug length increased at the upstream inclined pipes and decreased at the downstream inclined pipes with increasing pipe diameter. The possibility of pseudo-slug generation was increased at large pipe diameters even at high sink capacities. At low sink capacities, no pseudo-slugs were generated at high superficial velocities. The slug flow characteristics were more affected by low superficial gas and liquid velocities, large pipe diameters and shallow pipeline inclinations.
Enhanced Fracture Stimulation in the Deep Morrow Sandstone in Western Oklahoma
Authors: Ely John W. , Martin Michael A. , Duenas Jose J. , Trythall Jerry R.
Published: December 2007

Late in the fall of 2000 a concerted effort was initiated to optimize fracture stimulation of the Deep Morrow Sandstone in Mayfield area of Western Oklahoma. The producing horizons, typically four or more stacked pays, in the Mayfield area are from 17,000 to 20,500 feet and exhibit extreme heterogeneity including tremendous variations in permeability, pressure, and aerial extent of the reservoir. The presence of severe depletion in some of the zones greatly complicates completion techniques.

The initial approach was to utilize pressure data from previous treatments in the field and attempt to gain qualitative values for stress profiles. Based upon this data available a procedure was developed to optimize stimulation treatments using an iterative process. The use of pre-job FET's allowed evaluation of fluid efficiency and also to identify severe tortuosity problems.

The use of field proven techniques used in other deep high temperature reservoirs allowed for removal of severe near-wellbore problems allowing for placement of up to 7 pound per gallon bauxite in wells below 20,000 feet. The authors will elucidate the step-by-step procedures utilized in selection of pad volume, leak-off control methods, and specific procedures for removal of tortuosity. Additionally we will discuss the success and failures of zonal isolation techniques and the successful use of pseudo-limited entry on some of the producing horizons.

The new procedure allowed for successful placement of higher concentration of proppant and much larger volumes of proppant.

A major part of the paper will be comparing the newgeneration treatment results to offset operators and comparison of production data on a well-to-well basis.
Use of After Closure Analysis to Improve Hydraulic Fracturing Designs, Application on Algeria's In-Adaoui gas Field.
Authors: Benelkadi S. , Belhaouas R. , Sahar M.
Published: December 2007

Hydraulic fracturing design is highly dependent on the knowledge of the injection fluid efficiency. This parameter is generally derived from the interpretation of the calibration tests fall offs. Two popular methods are the square root of time and Nolte's G function1,2,3,4. Such interpretations are not always straightforward and can lead in some practical applications to the failure of propant placement i.e: a screen out with an impact on the post frac well's productivity.

In this paper a new interpretation technique for closure pressure determination is presented. It is based on a novel utilisation of Nolte's F function5. Field cases on Algeria's In-Adaoui field are analysed. Proppant placement failures are explained. These examples demonstrate the usefulness of the F function for improving hydraulic fracturing design whether for a conventional permeabilty estimation or for closure pressure and hence efficiency determination.
Selection of Foam Flushes and Foamed Cement Proves Effective for Remedial Operations of Low-Pressured Formations—Case Histories
Authors: Millard Matt , Getzlaf Don , Griffith James E.
Published: December 2007

Remedial cementing operations and zone abandonment are difficult to accomplish when low-pressure formations possess high feed rates at low, or even vacuum, surface pressures. Such is the case with several heavy-oil wells recently abandoned in Western Canada. These wells and their respective formations average an economic life of approximately ten years, during which a large amount of formation sand is produced. Traditionally, whenever exposed to hydrostatic pressure, these zones exhibit a vacuum at very large feedrates. Scorecard results of conventional cement squeezes required an average of 2.6 attempts to obtain a positive squeeze pressure. Many conventional cementing abandonment attempts were unsuccessful, resulting in the placement of a casing patch across the open perforations. The mechanical seal was effective in sealing the wellbore, which allowed exploitation of deeper zones. However, this seal reduced the casing internal diameter and can limit further production operations. Also, this mechanical seal may not serve as a final abandonment under certain government regulations.

The solution to this challenge was developed by tailoring a treatment pumping schedule that incorporates the use of foamed nonreactive, reactive spacers and foamed cement blends. This new treatment design was used on several wells in early 2002. On most of the wells, positive squeeze pressure was obtained on the first attempt and saved approximately CAD $15,000 per well. The improved process is now being planned for two adjacent fields. This paper details the well challenges and results found by a Canadian operator to successfully abandon low-pressure, heavy-oil producing zones. The solution developed for the case history wells is also presented.
Buckling of Tubulars Inside Wellbores: A Review on Recent Theoretical and Experimental Works
Authors: Cunha J. C.
Published: December 2007

Buckling behavior of tubulars inside wellbores is the major subject of many articles. This paper presents a general overview on most of the material available in the literature on the subject and also comments on the different, and sometimes conflicting solutions presented in various works.

Different aspects of the phenomenon are discussed including sinusoidal (lateral) and helical buckling and influence of torque.
Experimental and Simulation Studies of Sequestration of Supercritical Carbon Dioxide in Depleted Gas Reservoirs
Authors: Seo J. G. , Mamora D. D.
Published: December 2007

This paper presents experimental and simulation studies to evaluate the feasibility of sequestering supercritical CO2 in depleted gas reservoirs. Experimental results were simulated to obtain gas-liquid relative permeability curves used in the field simulation study.

A 3D simulation model of one eighth of a 5-spot pattern was constructed to evaluate injection of supercritical CO2 under typical field conditions. Simulation results indicate the following. First, a large amount of CO2 in sequestered: about 1.2 million tons in 29 years (40-acre pattern), and 4.8 million tons in 56 years (80-acre pattern). Second, a significant amount of natural gas is also produced: about 1.3 BSCF or 74% OGIP (40-acre pattern), and 4.9 BSCF or 68% OGIP (80-acre pattern). Third, at $2.00/MSCF, produced gas revenue amounts to about $2.6 million to $9.8 million, which could help defray the cost of CO2 sequestration. In short, CO2 sequestration in depleted gas reservoirs appears to be a win-win technology.
Oklahoma's New Guardian Program Guidance for the Assessment and Cleanup of Complex Crude Oil and Condensate Spills
Authors: Billingsley Patricia
Published: December 2007

Pollution Abatement Division staff have been working with oil industry representatives, the American Petroleum Institute (API), and Risk Based Corrective Action (RBCA) experts to thoroughly revise our guidance for complex spills and discovered historic pollution. While the focus is on crude and condensate from production sites, pipelines, and tank farms, cleanup of refined hydrocarbons is also briefly discussed. There are seven steps from assessment through cleanup or stabilization to closure. A new TPH analytical method, similar to Texas method 1005 pushed to C35 but with 4 reporting ranges, is being developed by the Oklahoma State Department of Environmental Quality. There is also a revised brochure for reporting and responding to spills, which has guidance for immediate and short term response actions.

In this new system, operators can choose to follow the revised category/risk factor pathway, which has fixed numerical cleanup criteria; or can prove stabilization, with monitored natural attenuation for the "cleanup"; or can instead use a RBCA approach. The PERF group did a fractionation analyses of numerous crude oils and condensates from both Oklahoma and worldwide to determine their levels of potentially harmful compounds. The numerical category cleanup criteria and a new RBCA Tier 1 lookup table contain risk-related cleanup levels based on these analyses, as well as oil mobility limits in soils and the effects of crude and condensate in the root zone on plants. The guidance also specifies the software to be used (developed for Oklahoma by API) if a company decides to do a site specific Tier 2 or 3 RBCA.

Oklahoma Centennial Commemorative Medallion Design by Betty Price, Executive Director, Oklahoma Arts Council.
The Mitigation of International Security Risk
Authors: Keable Kevin BP , Hitchcock Mike
Published: December 2007

As the oil and gas industry becomes more and more reliant on developing fields in third world and developing countries, they must also embrace the fact that whilst the rewards are certainly higher, so are the risks. Simply put, everything comes at a price. Terrorism, the threat of physical attack, fraud and corruption are of great concern to those responsible for investing in and sending staff to the higher risk regions of the world. But our industry has in certain areas been too blasé about the security risks in many countries and is guilty of reacting to problems rather than proactively reducing the risk to staff and assets. This paper outlines some of the background to the particular challenges faced by the oil and gas industry and solutions to the ever present security puzzle.
Determination of Drilling Mud Density Change with Pressure and Temperature Made Simple and Accurate by ANN
Authors: Osman E. A. , Aggour M. A.
Published: December 2007

An artificial neural networks (ANN) model has been developed to provide accurate predictions of mud density as a function of mud type, pressure and temperature. Available experimental measurements of water-base and oil-base drilling fluids at pressures ranging from 0 to 1400 psi and temperatures up to 400 °F were used to develop and test the ANN model. With the knowledge of the drilling mud type (water-base, or oil-base) and its density at standard conditions (0 psi and 70 °F) the developed model provides predictions of the density at any temperature and pressure (within the ranges studied) with an average absolute percent error of 0.367, a root mean squared error of 0.0056 and a correlation coefficient of 0.9998.
North Kuwait Down-hole Corrosion Management Challenge and the Use of New Corrosion Detection Tools to Define the Extent of the Problem
Authors: Al-Ajmi Moudi Fahad , Attid Juma K. , Daye Alex
Published: December 2007

The North Kuwait (NK) Development Plan calls for rapid increase in NK production, mainly through the implementation of waterflooding in NK major reservoirs. The new production profile incorporates increased water production and, based on corrosion prediction models, results in elevated corrosion rates in down-hole completion equipment. This predicted increased corrosion has already become a reality in the past three years. Severe down-hole corrosion in production and injection wells has resulted in tubing and casing failures and severe casing/tubing corrosions. Remediation of these wells has resulted in problematic, high cost workovers, and in one case, the loss of the productive interval and the associated reserves.

To manage current and future corrosion in NK, an extensive corrosion-monitoring program has been implemented to initially identify the extent of corrosion in the current well stock and then to adopt corrosion prevention strategies to mitigate the problem and reduce the associated cost and production impact. The down-hole internal corrosion monitoring effort is one of the first steps in implementing the NK Corrosion Management Plan.

This paper discusses the results of the program to date and describes the diagnostic tools used to effectively monitor the extent of down-hole corrosion in North Kuwait. Different tools such as the caliper, MicroVertiLog tool (MVRT), and surface inspection methods have been utilized to quantify down-hole corrosion. The paper also compares MVRT tool response with caliper and surface inspection data in an effort to ensure down-hole corrosion detection corresponds with results measured at surface. This will allow immediate corrective action to be taken for the completions based on down-hole log results.
Improving the Production of Heavy Emulsion Crudes in the Bahrain Field: Experimental and Field Investigations
Authors: Al-Bastaki N. , Abbas A. , Zubari H.
Published: December 2007

In crude oil production, the generation of heavy oil/water emulsions can result in a significant drop in the production rate due to the high viscosities of the emulsions. The strong agitation and mixing that takes place at the inlet of the well bore together with the presence of the naturally existing emulsifying agents in the crude contribute to the formation of the emulsion. A number of methods can be used to mitigate this problem such as the injection of surfactants into the formation and surface treatment. The objective of this paper is two-folds. Firstly, the results of an experimental program carried out to evaluate the efficiency of several surfactants to demulsify crude oil / water emulsions are presented. Secondly, a novel cost effective technique for injecting the surfactant into the well utilising existing gas lift facilities at the well heads is described together with a number of other techniques which have been tested for treatment of emulsions.

The experimental study was performed on crude oil/water emulsion samples obtained from two sandstone reservoirs in the Bahrain field. The measurements included effects of surfactants on the degree of demulsification, surface tension and shear viscosity. An optimum surfactant/emulsion volume ratio of around 1.5 to 2% was noticed in most cases for the specific wells investigated. The addition of surfactants considerably reduced the shear viscosity and surface tension of the emulsion. As expected the surface interfacial tensions decreased with increasing temperature.
Evaluation of Special Enzymes as a Means to Remove Formation Damage Induced by Drill -in Fluids in Horizontal Gas Wells in Tight Reservoirs
Authors: Siddiqui M. A. , Nasr-El-Din H. A.
Published: December 2007

Drill-in fluids contains biopolymers such as xanthan gums, cellulose and/or starch along with bridging agents like sized calcium carbonate particles. These polymers are used to enhance the carrying capacity of the mud and to form a filter cake on the formation to minimize leak-off of the drilling fluids into the formation.

Proper removal of drilling mud filter cake is essential to minimize formation damage. The damage becomes more intense in tight formations, especially in horizontal gas wells where the draw down is not high enough to dislodge the filter cake. Another source of damage is the mud filtrate where water blockage can occur in tight formations, especially sandstone reservoirs.

Thorough lab and field investigations of formation damage induced by drill-in fluids (water based mud) were conducted. A mini-flow loop was used to assess formation damaged induced by various polymers present in the drill fluid. Various cleaning fluids were examined and their effectiveness in removing the filter cake was determined. The cleaning fluids included: specific enzymes, mild acids, surfactants and mutual solvents, and combinations of these fluids. The retained permeability of reservoir cores was determined for each cleaning fluid. This paper presents results obtained from the lab and recommendation made for field application. Field treatment was conducted in a horizontal gas well which resulted in significant increases in gas production.
Al-Huwaisah Reservoir: The Long Journey to Improved Oil Recovery!
Authors: Al-Mugheiry Mohammed Adil , Mueller Guy , Braas Marcel , Materna Thomas , Davies Huw , Hsu Chia Fu , Keating John
Published: December 2007

After 30 years of production history in the Al-Huwaisah oil field of North Oman, it is still possible to bring best wells on stream. Both vertical and horizontal technologies have been implemented with variable combinations of gas-lifted or ESP completions and barefoot or lined reservoir sections.

In addition, these technologies are implemented on this complex carbonate reservoir characterized by a high degree of heterogeneity embedded in four depositional environments (i.e. Channel, Fore Reef, Main Reef and Back Reef) and spread over an area of 22km by 10km with zones of strong and poor aquifer support. This necessitates the need for a sound data gathering strategy to manage the subsurface uncertainties.

The improvement in recent production history was mainly the result of implementing a multidisciplinary team approach to define a more structured methodology for identifying the remaining oil targets and ranking them using basic petroleum engineering tools in a more synergistic fashion.

Past operational experience has also helped in selecting the best completion and stimulation practices. The outcome of implementing these practices on such a complex field showed that improved oil recovery requires a more flexible approach in field development philosophy in the sense that not always horizontal well technology is better than vertical or lined wells are better than barefoot.

The field is currently being evaluated for a possible application of Water-Alternate-Gas (or WAG) hydrocarbon recovery technique. Only parts of the field are found to be acceptable for the WAG pilot test according to the specified pre-requisites for this technology.

It is evident that technology solutions for complex carbonate field such as Al-Huwaisah calls for a ‘;dynamic focus’ in the sense that different parts of the field may require different types of technologies to meet the challenges of extremely variable complexity.
3D Model for Rock Strength & In-Situ Stresses in the Khuff Formation of Ghawar Field, Methodologies & Applications
Authors: Al-Ruwaili Saleh B. , Chardac Olivier
Published: December 2007

Knowledge of geomechanical attributes has positive merits for drilling in hydrocarbon formations. In the Ghawar field, the Khuff is a deep, carbonate gas-bearing formation. Several development wells have been drilled into this formation and conventional logging data was acquired in them. Such data has been exploited in generating geomechanical attributes along the Khuff formation in those wells. Furthermore, hard data like minifrac tests and core mechanical properties was available in some of the wells and utilized in calibrating and validating the computed geomechanical properties.

A study was conducted to develop a 3-dimensional characterization of geomechanical attributes in the Hawiyah- Khuff formation of the Ghawar field. The study was performed to provide a model that, together with existing geologic models, can be used to predict regions of drilling difficulty, provide guidance in selecting drilling bits, and help in designing drilling mud and optimizing hydraulic fracturing jobs in the field. The study established correlations between the geomechanical and the geological attributes in Hawiyah-Khuff wells. Then, these correlations were used with a pre-existing Hawiyah-Khuff geocellular model to map the geomechanical attributes away from the wells in the 3D Hawiyah-Khuff space. Rock strength, minimum and maximum horizontal stresses are among the properties that were mapped, for the first time, in the 3D Khuff horizon.

The 3-D geomechanical model is consistent with observed trends in drilling difficulty, and with the requirements for hydraulic fracturing within the Khuff horizons. The model has been used in assessing the borehole stability of deviated wells planned for the field. We present some illustrations and example applications in the paper.
An Innovative Approach for Logging Short String Side of Dual Completion Wells - A Case study from Kuwait
Authors: Al-Shaheen Saeed , Al-Mutairi Faisal , Chandran T. P. R. , Zaki Ahmed
Published: December 2007

This paper details an innovative technology to carry out logging operations in short string side of the dual completion wells. A program was initiated to carry out production logging in a Kuwait carbonate reservoir that recently began a secondary recovery project. The ability to measure zonal contributions and water entry in the target flood zones is critical for flood monitoring, designing future conformance control operations and profile modification jobs.

Most of the wells in the waterflood area are completed with dual tubing strings. The production logging target interval is generally in the short string of the dual completion, making wireline logging difficult due to the risk of entanglement with long string. Another concern is the fluid flow profile in the constricted area between two packers due to the presence of long string. Generally such surveillance requirements are hardly attempted, and this is considered as one of the major drawback of dual completion system itself.

A program was developed to record production logging in the short string side of a dual completion well. Coiled tubing with straightened bottom and threaded cable was used to convey production-logging tools in the short string. Several safety features were added to this system in order to ensure safe data acquisition. Upon success from first trial, the same procedure was repeated in several wells and results are quite encouraging.

Details of the initial obstacles that were faced in the beginning of the project and the methods used to resolve them will be discussed in this paper. The acquisition and processed results will be also discussed. It is worth mentioning that, all logging operations were successful and no operational problems encountered so far.
Variable Cementation Factor Determination (Empirical Methods)
Authors: Tabibi M. , Emadi M. A.
Published: December 2007

Cementation Factor is the most important parameter of water saturation calculations in Archie Formula. In fact the amount of this parameter defines the magnitude of pore volume in water saturation calculations. Cementation factor is not a constant value, but it largely varies according to many parameters in a field peculiar to reservoir characteristics. In addition accurate cementation factor "m" will effect on molecular diffusion coefficient in porous media in gas injection project. The most practical and reliable value of this parameter can be extracted from core analyses. In this new method, the attempt is to approach to a method of achieving variable m using the most effective reservoir parameters for any arbitrary interval of reservoir.
Smart Well Technologies Implementation in PDO for Production & Reservoir Management & Control
Authors: Al-Khodhori Shaikhan Mohammed
Published: December 2007

PDO currently operates more than 4000 wells in over 100 fields. The fields are diverse in terms of their reservoir, drive and development strategies. Despite this diversity, there are strong common drivers for smart wells/fields. Many fields are artificially lifted (beam pumps in S. Oman, gas lift in N. and central Oman, increasingly ESPs in all areas) with SCADA systems already in place. There is a progressive drive towards centralised, automated production facilities for reasons of safety. Reservoir depths and low drilling costs support relatively dense economic well spacing where it is technically feasible to connect large amounts of reservoir to a single wellbore; this saves development CAPEX but makes maintaining effective control of the reservoir more difficult.

Smart wells is an umbrella term referring to the systemic integration of emerging down-hole measurement, communication, control and processing technologies in well and asset design. As an integrated technology bundle, they have the potential fundamentally to change the E&P industry. A range of smart technology trials have been conducted and/or are planned, including down-hole monitoring, measurement, controlling and artificial lift optimisation.

PDO is applying many smart well technologies to monitor, measure, control and optimise production from multi lateral wells. This paper focuses on following applied technologies; Distributed Temperature Sensing (DTS) to monitor water and steam flooding wells.Down-Hole 2-Phase Metering in ESP and BP wells to measure water cut of dual lateral wells.Digital Hydraulic Control Valves to control production of a multilateral well.

The paper is intended to cover the above applied smart well technology trials, share the experience with respect to their outcomes (success and failures) during the execution. It also provides an assessment of the values of these technologies to PDO.
Sand Control during Drilling, Perforation, Completion and Production
Authors: Abass H. H. , Habbtar A. H. , Shebatalhamd A.
Published: December 2007

Sand control has been a challenge to the petroleum industry since oil and gas was produced from weakly cemented sandstone formations. Several techniques have been applied; 1) restricted (critical) production rate, 2) screen and/or gravel packing, 3) sand consolidation, 4) FracPacking, 5) oriented and/or selective perforation, and 6) combination of any of the above.

Sand formations may fail in compression, tension, and cohesion that trigger sand production. The compressive failure occurs during drilling where the rock cannot withstand the new stress field and/or the cementation materials have deteriorated from mud filtrate exposure. The calculation of mud weight to prevent compressive failure will be presented in this paper. Additionally the failed zone is usually oriented in the direction of minimum horizontal stress which can be avoided during perforation by orienting the perforation tunnels in the direction of maximum horizontal stress. During completion the cementation materials should be protected from completion fluids. During production a pressure drawdown is established for a given production rate. This pressure drawdown may cause rock failure in tension or cohesion (erosion) leading to sand production. The near-wellbore pressure is caused by skin damage due to reduced permeability, stressed region, convergence flow, and partial penetration. This paper presents a model to determine the critical pressure drawdown based on relating the near-wellbore pressure drawdown to the tensile and cohesive strengths of the formation. Hydraulic fracturing, referred to as FracPack, may be applied to alleviate the near-wellbore pressure drawdown below the critical value that causes sand failure. Two fracture parameters are designed to achieve this goal; fracture length and fracture conductivity. This paper presents a design criterion to determine these parameters to optimize a FracPack design for sand control.

Examples from a field in Saudi Arabia will be used to validate the application of controlling sand production using screenless FracPack completion. In these wells a FracPack treatment alone controls sand production. The multirate test used in these wells and the FracPack design for fracturing treatments will be presented.
The Use Of Surface Controlled Hydraulic Interval Control Valves For The Management Of Water Production In The Saih Rawl Field, Sultanate Of Oman
Authors: Boyle Maurice , Earl Jeremy , Ojulari Bayo , Al-Khadori Shaikhan , Al-Farsi Nasser
Published: December 2007

This paper presents a case history of the use of remotely operated hydraulic Interval Control Valves (ICV's) as a simple and cost effective method of controlling multiple laterals for selective water shutoff. Post installation production testing and impact on production are described.

The Saih Rawl Shuaiba reservoir in central Oman is a low permeability limestone reservoir producing light oil with pressure maintenance by means of a water flood. Extensive development started in the early 1990's when multi-lateral horizontal well technology enabled economic production rates from wells and sustainable water injection for the water flood. Multi-lateral wells of 4 to 7 legs are typically drilled for both producers and injectors with producer to injector leg spacing gradually decreasing from 250 m in the initial development to 60 m at present. As a consequence of this development philosophy, production has been accelerated, but control of sweep and water breakthrough has become a problem.

A Digital Hydraulics intelligent well completion has been successfully installed and operated in a Saih Rawl Shuaiba well that allows each of the 4 laterals legs to be independently opened and closed at will from surface using three hydraulic lines. The concept is purely a hydraulic control system that allows for multiple downhole devices to be controlled with the minimum number of control lines. This is achieved using hydraulic pressure sequencing and a mechanical decoder downhole along with a hydraulically operated control valve to give simple on/off zonal control. Retrievable hydraulic line feed-through packers are used to isolate one lateral from another.

This intelligent well system has been integrated with the ESP installation with the provision of a hydraulic disconnect, allowing replacement of the ESP (upper completion section) without affecting the lower intelligent well section. Control line hydraulic continuity is re-established upon ESP replacement.
A New Solids-Free Non-Damaging High Temperature Lost-Circulation Pill: Development and First Field Applications
Authors: Samuel M. , Marcinew R. , Al-Harbi M. , Samuel E. , Xiao Z. , Ezzat A. M. , Khamees S. A. , Jarrett C. , Ginest N. H. , Bartko K. , Hembling D. , Nasr-El-Din H. A.
Published: December 2007

Excessive loss of high-density brines into the formation has always been a major concern during completion operations, since it leads to formation damage and well control issues. The problem becomes more complex at high temperatures and when the treatment involves running gravel-pack assemblies and downhole sand screens.

Typically, the fluidloss-control pills are composed of very high concentrations of crosslinked polymers with or without bridging particulates. The sealing mechanism of these pills is a combination of viscosity, solids bridging, and polymer filter-cake buildup on the porous rock. Due to the instability of polymers at high bottomhole temperatures, incompatibility with some divalent brines, and the necessity to cleanup with acid, a new solids-free lost-circulation pill that is stable for prolonged periods at high temperatures was developed.

This paper introduces the development and the first field application of a new solids-free non-damaging viscoelastic surfactant-based fluid-loss pill (VES-PILL). The single-additive system forms a "gel" with most completion brines currently used in well operations. Laboratory data demonstrate that this pill could be used up to 375°F. The "gel" structure of this system sustains viscosity high enough to effectively control or stop brine-loss, while maintaining a safe differential pressure into the formation.

Several "frac and pack" completions were performed for the first time in Saudi Arabia in the Pre-Khuff sweet-gas zones. The VES-PILL was used to prevent losses after perforating, fracturing and gravel-pack operations. The pill was used in the field up to 310°F, and brine-loss was effectively controlled for more than 3 days. The effectiveness of the pill was also demonstrated by a five-fold increase in surface pumping pressure during placement. The wells were produced at rates exceeding expectations without further remediation to cleanup the fluid-loss pill.
Large Compositional Reservoir Simulations with Parallelized Adaptive Implicit Methods
Authors: Caillabat Y. , Magras J- F. , Ricois O.
Published: December 2007

Simulation of large compositional reservoir models in an acceptable CPU time still remains a key issue for any reservoir simulator software. Parallel computing is thus required to speed up the simulations and robust numerical solutions need to be implemented to insure accurate results especially for simulations of complex compositional physics. In that context, classical fully implicit schemes are often unusable due to memory and CPU requirements. We suggest new time discretization methods, which mix the accuracy and stability of the fully implicit methods and CPU performances and low memory consumption of the explicit ones. Within these approaches, a fully implicit scheme is applied in parts of the reservoir with highest physical property variations, and an explicit method is used in the other ones. Explicit schemes are delimited by a stability CFL condition. Explicit cells with large variations on the unknowns, are switched dynamically to implicit ones to improve global simulation CPU performances. These status computations are based on either threshold or spectral criteria. Implicit gridblocks may also be discretized using fully implicit or quasi-implicit schemes depending on the fluid composition variations.

These different schemes have been parallelized and integrated in a multi-purpose industrial reservoir simulator. The CFL criteria are discussed and tested on academic reference cases and then, comparisons of the available methods are presented for large compositional real case studies run on different parallel hardware platforms.
History Matching of Object-Based Stochastic Reservoir Models
Authors: Hu Lin Y.
Published: December 2007

Object-based models can be regarded as arrangements of a population of geometrical objects in space. In reservoir modeling, these models are often used for describing meandering channel systems, fracture networks etc., where geological objects can be clearly identified. Unlike pixel-based models, object-based models can provide geologically realistic representations of reservoir heterogeneities even at the appraisal stage with few well data. Although an extensive literature on object-based models is available, little has been done for constraining these models to dynamic data (history matching). This is however of great importance for their application in reservoir engineering.

This paper first reviews the basic concepts of the widely used object-based Boolean model. Then, we present a methodology for calibrating Boolean simulations to dynamic production data. This methodology is based on a generalization of the gradual deformation method that was initially developed for calibrating pixel-based Gaussian-related reservoir models to dynamic data. Finally, a simple synthetic example is presented and the results show the validity of the above methodology. In particular, this methodology is potentially applicable to history matching of fractured reservoir models.
The Contractual Form of Iran's Buy-back Contracts in Comparison with Production Sharing and Service Contract
Authors: Ebrahimi S. N. , Khouzani A. Shiroui
Published: December 2007

Since the Constitution of the Islamic Republic of Iran (1979) does not allow foreign companies to own equity stakes in hydrocarbon projects, Iran has developed a new mechanism in line with the Constitution to facilitate the engagement of foreign oil companies in development of oil/gas fields. Such a mechanism resembles a typical buy-back arrangement, under which a foreign company provides the funding for, and necessary equipment and services for the establishment, development or updating a project and agrees to purchase back a portion of the production such as those goods or services produced in that project. This mechanism, however, is a hybrid of a service contract and a production sharing agreement, although it is much closer to the former.

Under this mechanism a foreign oil company provides the fund for, expertise, equipment and machinery for the development of a gas/oil field. In return, the petroleum costs, constituting Capital Costs, Non-Capital Costs, Operating Costs, Bank Charges (interests), and Remuneration Fee, will be recovered through the revenues generated from the filed as the result of the development operations carried out by the foreign oil company as contractor. Alternatively, the oil/gas produced as the result of the development operations may be sold to the oil company under the Crude Oil Sales Agreement at the prevailing market price against the expenses and costs charged to the Project Account by the contractor. The development operations are carried out under the control, supervision, inspection and audit of Iranian National Oil Company (a state oil company). Although this provides a degree of control over operations of the private contractor, development operations are carried out under the management of the risk-taking foreign oil company. Thus, for instance, the risk of any shortage of revenue shall be borne by such company.

In this article, we provide a true picture of such a particular formula, distinguishing it from typical buy-back in industrial projects, service contracts and production sharing agreements in oil and gas business. To achieve that goal, a brief explanation of the basic elements of such arrangements is a prerequisite for our discussion.