bluuebunny/crossref_metadata_2025 huggingface dataset:
The Challenge that Completion Types Present to Scale inhibitor squeeze Chemical Placement: A Novel Solution using a Self-Diverting Scale Inhibitor Squeeze Process
Authors: Feasey N. D. , Jordan M. M. , Mackay E. J. , Collins I. R.
Published: December 2007

The control of inorganic scale deposition within the reservoir under both natural depletion and injection water support has been a challenge to the oil industry for a number of decades. The challenge has remained identifying the location of water breakthrough within the production interval and the subsequent injection of scale inhibitor into these zones to prevent scale formation within the near welbore and production tubing. As completion technology has advanced, and more complicated completions have been developed and installed to increase the rate of oil recovery, the challenges of water management and scale control have become significant factors if long term production from these wells is to be maintained.

This paper will outline the challenges of chemical deployment via bullheading into subsea wells completed in high permeability reservoirs with sand control technology. The factors considered when designing a self-diverting scale inhibitor system will be outlined in terms of viscosity profile of the chemical and overflush fluid, impact of temperature on fluid viscosity, pump rate, shear effects, tubing diameter vs. wellbore friction and the impact of radial flow on viscosity. Modelling data from vertical and horizontal production wells will be used to illustrate the challenges that pump rate changes and a self-diverting scale inhibitor system has to overcome to allow effective deployed of scale inhibitor without the need for coiled tubing in long (500ft to 3,000 ft) wells in 2 Darcy reservoirs.

The value of this technology in terms of the economic factors will be outlined with field examples where coiled tubing and bullhead applications will be compared and contrasted to illustrate the value in terms of total cost of operation that the self-diverting technology can offer.
Pushing the Limits in Hydraulic Fracture Design
Authors: Demarchos A. S. , Chomatas A. S. , Economides M. J. , Mach J. M. , Wolcott D. S.
Published: December 2007

In a number of previous publications we have introduced the concept of Unified Fracture Design (UFD) with a central theme of maximizing the dimensionless productivity index (JD) following a hydraulic fracture treatment. We have shown that for a given mass of proppant to be injected in a well with an assigned drainage in a reservoir of a given permeability there exists a specific dimensionless fracture conductivity at which the JD becomes maximum. We called this the optimum conductivity. Smaller and larger values of this conductivity result in smaller JDs. All the important fracture and reservoir magnitudes of permeabilities and volumes are related through the Proppant Number. Once the optimum conductivity is determined (which for a large range of Proppant Numbers is equal to 1.6) then the ideal fracture dimensions (length and width) are de facto set and they should be considered as the desirable target.

For each injected proppant mass there is a corresponding Proppant Number and at the optimum conductivity the dimensionless PI can be readily determined. Increasing the proppant mass or the proppant-pack permeability would result in an increase in the JD, which has a maximum limit of approximately 1.9. This value can never be accomplished in reality and there are three reasons preventing it, one economic and two physical. The economic reason is obvious. Increasing the job size would result in the flattening of benefits, not justifying the incremental costs. In the same vein, using a much better (and more expensive) proppant may not be justified by similarly flattening benefits.

Of the physical problems, the first affects low-permeability reservoirs where the indicated fracture width may be too small; it cannot be less than three proppant diameters. For high-permeability reservoirs, indicated very large widths will certainly result in very large net pressures, exceeding operational limits. The latter may also lead to unacceptable fracture heights.

We present here a series of parametric studies pushing the physical limits of fracturing in a wide range of reservoirs by injecting very large proppant volumes and experimenting with extraordinarily large proppant sizes (large proppant pack permeabilities) seeking the maximization of the JD within reasonable economic limits. This work appears to be particularly suited for high permeability formations and it shows that current industry practices are overly conservative and timid and a more bullish approach would lead to major production enhancement benefits.
An Innovative System for Complete Cleanup of a Drill-In Fluid Filter Cake
Authors: Todd Brad , Ali Syed , Whitfill Donald L. , Haggerty Tim
Published: December 2007

Proposal

As part of a comprehensive program to develop delayed filter cake breakers, a drill-in fluid with magnesium oxide (mag-ox) bridging particles and an ammonium chloride-based cleanup solution was developed. The mag-ox particles are insoluble in water and standard drill-in fluid-based brine such as sodium chloride, but these particles are readily soluble in ammonium chloride or ammonium citrate. Thus, an ammonium chloride-based cleanup can be formulated that will dissolve the bridging particles and other drill-in fluid components without using acid-based systems. Because this technology was of specific interest for injector well applications, a laboratory study was undertaken to evaluate this novel system. This paper summarizes laboratory work and radial flow loop test results, and discusses possible field applications.

Filter-cake cleanup of injection wells can be especially problematic because operational constraints often preclude backflowing the well to remove the residual filter cake. Consequently, injection remains impaired if the residual filter cake is not removed by other means. The highly reactive nature of standard treatments may remove the filter cake at the point of circulation before the treatment can be placed over the entire openhole interval. A need exists for cleanup solutions that have a delayed effect on filter-cake integrity, allowing the cleanup solution to be circulated across the entire interval. Preferably, the treatment's reaction with the filter cake would commence when the entire solution is in place and continue until the filter cake is uniformly removed. The ideal placement of a treatment would be in the gravel-pack carrier fluid, where it would provide enough of a delayed reaction to allow the gravel pack to be placed with an alpha/beta wave technique before fluid-loss control is lost.
Predicting and Monitoring Fluid Invasion in Exploratory Drilling
Authors: Martins A. L. , Waldmann A. T. A. , Aragão A. F. L. , Lomba R. F. T.
Published: December 2007

The present study proposes, through the coupling of a linear filtration formulation (lab configuration) and a radial single phase formulation (wellbore vicinity), to predict fluid invasion depth of drilling fluid filtrate in the reservoir rock. Modeling is validated with linear and radial lab tests as well as with resistivity logs run in offshore wells from Campos basin.

The proposed methodology is a requirement for optimum drilling fluid design to be used in the drilling of reservoir sections in both exploratory and development wells in Campos Basin, offshore Brazil.
An Investigation of the Extensional Viscosity of Polymer Based Fluids as a Possible Mechanism of Internal Cake Formation
Authors: Khan R. , Kuru E. , Tremblay B. , Saasen A.
Published: December 2007

Formation of internal cake due to the invasion of reservoir rock by drilling, completion, and fracturing fluids is known to be one of the major causes of productivity reduction. Although the causes of internal cake formation are relatively well identified, the actual physical mechanisms involved in internal cake formation are yet to be understood. In particular, a quantitative means of relating physical properties of fluids to the degree of productivity reduction are not well established. A detailed investigation on the role of the rheology of viscoelastic fluids on the formation of "internal filter cakes" is, therefore, needed.

The extensional viscosity for pure liquids without any structure is 3 times the shear viscosity. For these liquids, contribution of the extensional viscosity to the pressure loss is, therefore, constant and often neglected. However, for viscoelastic fluids, such as polymer based drilling and completion fluids, the extensional viscosity may be several orders of magnitude larger than the shear viscosity. This will lead to a significant increase in pressure loss, which is very often attributed to the development of internal cake.

A series of core flow experiments have been conducted to investigate the possible relationship among the polymer concentration, fluid extensional viscosity, shear viscosity, filtration loss characteristics, and pressure drop across the core samples and hence, any change in the original rock permeability.

Results of extensional and shear viscosity measurements, API filtration loss tests, and formation damage tests conducted by using two different Partially Hydrolized Polyacrylamide (PHPA) solutions (1.5 and 3.0 lb/bbl) are shown in this paper.

Comparison of the PHPA test results with the previously published Xanthan Gum (XG) test results are also provided.
Strategy for Designing an Optimum Drill-In Fluid Utilizing Rock and Petrophysical Properties
Authors: Luyster M. R. , Ali S. A. , Guzman J. , Mason S. , Dick M.
Published: December 2007

Relatively heavy crude production has historically been a problem in vertical completions in mature and new development fields in the Gulf of Mexico. Horizontal wells have been utilized to minimize water coning in potential completions that are close to the oil/water contact. However, horizontal completion costs are typically 60% more than vertical completions, consequently well and fluid design are critical to minimizing costs associated with drilling (fluid losses, wellbore stability, etc.).In addition to the engineering challenges for horizontal drilling, formulating a reservoir drill-in fluid (RDF) that minimizes invasion and fluid losses to the reservoir, provides compatibility between the reservoir fluids and the RDF fluid, and readily cleans-up is critical to success.

This paper will demonstrate the use of sidewall and conventional core material and subsequent petrophysical techniques to design a compatible RDF system. Core material from offset wells and previous vertical wells in several sands were utilized to develop bridging-material blends, determine sorting, texture, and particle and pore size.The authors discuss the advantages and disadvantages of using this type of material as well as that of a relatively new computer technique that allows a pore-size distribution to be rapidly calculated from core material.Another technique utilizes the rock attributes and log information in conjunction with a rock catalog to facilitate rapid determination from analogs. This type of data, in turn, can ultimately be utilized to design an RDF system.As such, this method will also be described and contrasted with traditional methods.

Finally, case histories from several recently drilled horizontal wells that incorporated the subsequent RDF bridging-solids design using the aforementioned techniques will be presented. Fluid losses and solids loading will be examined with respect to the RDF designs.
A Potassium Formate Milling Fluid Breaks the 400° Fahrenheit Barrier in a Deep Tuscaloosa Coiled Tubing Clean-out
Authors: Messler D. , Kippie D. , Broach M. , Benson D.
Published: December 2007

This paper will detail the successful operation to remove a barite plug from this wellbore using a viscoelastic fluid, with true yield stress properties. Extensive field rheologies, pumping rates, and pressures were captured; and compared with those predicted by modeling. The mechanical and chemical maintenance of the fluid system during the operation will also be discussed.

The development of this fluid enabled a coiled tubing intervention to go forward, as planned. In contrast to an earlier attempt, the coiled tubing successfully reached total depth (TD) while properties stayed within safe operating parameters. The milling operation was carried out, with over 185 ft of hole being recovered from the initial coiled tubing tag at 19,412 ft. At no time was there any danger of ‘sticking the coiled tubing’ or being unable to circulate due to excessive friction pressures.

The successful field application of this technologically advanced fluid system in combination with sophisticated computer engineering software, gives the industry a new tool in attempting deep HTHP coiled tubing workovers.
Brine Effects on Hydration Rates for Polymers Used in Completion and Workover Operations
Authors: Beall Brian B. , Monroe Terry D. , Vollmer Daniel P. , Hanna Farid T.
Published: December 2007

Polymers used in completion and workover operations can consist of cellulose, cellulose derivatives, guar and guar derivatives. Normally these polymers are used in completion and workover fluids consisting of potassium, sodium and ammonium chloride. As more wells are being completed in deeper and hotter environments, fluids composed of calcium chloride, calcium bromide, zinc bromide and combinations of all three are being used to control well pressures.

Studies were conducted on hydration rates in various brines for these polymers and are presented in graphical form. A correlation was also established to predict the hydration rates and the ultimate viscosity for hydroxyethylcellulose at temperature based on brine viscosity. These correlations are particularly useful for field operations during cold weather months.
Differential Pressure Valve Incorporated With the Single-Trip Horizontal Gravel Pack and Selective Stimulation System Improves Sand Control for Extended Reach Wells
Authors: Vilela Alvaro , Hightower Chad , Farias Rodrigo , Neumann Luis , Moura Heleno , Samuel Max , Augusto José
Published: December 2007

Proposal

Most of the reservoirs located in the Campos Basin, deepwater and ultra-deepwater offshore Brazil are described as unconsolidated sandstone that require sand control on both producers and water injection wells. Horizontal Open Hole Gravel Pack completions are the preferred method of development. Due to the recent discoveries of heavy oil reservoirs, there is a necessity of longer horizontal open hole sections. Low fracture gradients may limit the length of gravel pack in the open hole section because of the pressure increase during the Beta wave proppant deposition phase.

This system allows the gravel pack assembly to be installed and the gravel pack to be pumped during the alpha and beta wave deposition phases without the limitation of high pressures that could fracture the well. The benefits of the Single Trip Horizontal Gravel Pack and Selective Stimulation System (SHGPSS) using the differential valve include the ability to complete longer horizontal intervals, valuable rig-time savings and, efficient mechanical diversion of the stimulation fluid.

This paper outlines the first application of the SHGPSS system using a differential valve to successfully complete a horizontal well in the Campos Basin, offshore Brazil. The need for a differential valve is primarily in horizontal gravel packing operations when normal circulating rates and pressures around the openhole would exceed formation break down pressure. The valve is intended to be easily spaced out and run in the washpipe. At a predetermined differential pressure the valve opens and the return flow path distance around the bottom of the tailpipe is shortened, thus reducing backpressure preventing filter cake damage without slowing the pump rate.

Economic considerations along with completion efficiencies are especially important on deepwater, subsea completions. The utilization of differential valves allows completion of extended-reach open hole wells and/or low fracture gradient reservoirs insuring alpha and beta wave proppant deposition phases yielding efficient completions with improved coverage.
A New Model for Predicting Wormhole Structure and Formation in Acid Stimulation of Carbonates
Authors: Panga Mohan K. R. , Ziauddin Murtaza , Gandikota Ramakrishna , Balakotaiah Vemuri
Published: December 2007

We present a new averaged model for describing wormhole formation in carbonates. The model presented here captures the reaction and transport mechanisms at the pore scale and couples it to the Darcy scale through the use of two concentration variables, structure property correlations and mass transfer and dispersion coefficients. A salient feature of the model is that it captures both the reaction and mass transfer controlled regimes simultaneously, thus enabling the study of a wide range of stimulation fluids. Three important dimensionless parameters are identified in the model, namely, the Thiele modulus (pore scale parameter), Damköhler number (core scale parameter) and the acid capacity number that depends on the fluid/mineral system. Comparison of model predictions to experimental data shows good agreement. A preliminary analysis is presented on the factors that influence wormhole density.
Method for Characterizing Secondary and Tertiary Reactions Using Short Reservoir Cores
Authors: Ziauddin Murtaza , Gillard Matthew , Lecerf Bruno , Frenier Wayne , Archibald Iain , Healey Duncan
Published: December 2007

A new technique for characterizing secondary and tertiary reactions during sandstone matrix stimulation treatments is presented. In the new technique, traditional experiments on short reservoir cores are supplemented with measurement of the effluent element concentrations, batch reactor experiments and geochemical simulations to predict the extent of secondary and tertiary reactions in the reservoir treatment. Alternative methods of characterizing secondary and tertiary reactions, such as those using long core flow tests and laboratory radial flow setups, are reviewed.

The new design technique is used in designing a treatment for a well in the North Sea. Details of how this technique was applied to the treatment design are presented. Post-treatment data from the well showed a successful matrix treatment design. The production from the well increased by 1,400% immediately after the treatment. The 3-month stabilized production gain was 650%.
Hot Oil And Gas Wells Can Be Stimulated Without Acids
Authors: Frenier Wayne , Brady Mark , Al-Harthy Salah , Arangath Roberto , Chan Keng Seng , Flamant Nicolas , Samuel Mathew
Published: December 2007

A revolutionary family of treating fluids designed for the stimulation of critical, hot or exotic oil and gas wells has been developed through application of detailed chemical and engineering studies.1–3 Formulations based on the hydroxethylaminocarboxylic acid family of chelating agents have now been used to successfully increase production of oil and gas from wells in a variety of different formations. Included in the field test matrixes were new and producing wells drilled into carbonates and sandstone formations. The temperatures of the wells treated ranged from 230°F to 370°F (110-187°C) bottom hole static temperature (BHST).

Because these formulations do not contain high concentrations of corrosive mineral or organic acids (the formulations are less acidic than carbonated beverages), very low corrosion rates of the tubulars can be achieved by application of small amounts of special, inexpensive corrosion inhibitors. The mild fluids also are highly retarded so high-temperature carbonates can be stimulated and sensitive sandstone formations are not damaged. The fluids have reduced health, safety, and environmental (HSE) footprints because: (1) they are much less toxic to mammals as well as to aquatic organisms than mineral acids or organic acids such as HCl, HF or formic acid; (2) the fluids are returned to the surface at pH values between 5 and 7 and frequently can be added to normal well production fluids without neutralization; (3) because of much lower corrosion rates for corrosion resistant alloys (CRAs), lowered concentrations of Ni and Cr will be in the well returns compared with conventional acids that also may contain antimony (as a corrosion inhibitor).
Inverse Problems for Treatment of Laboratory Data on Injectivity Impairment
Authors: Bedrikovetsky P. , Marchesin D. , Hime G. , Siqueira A. G. , Serra A. L. , Rodrigues J. R. P. , Marchesin A. , Vinicius M.
Published: December 2007

Severe fall of injectivity in porous rock occurs from the practice in offshore fields of injecting sea water containing organic and mineral inclusions. In general, injection of poor quality water in a well curtails its injectivity. The injectivity loss is assumed to be due to particle retention in the porous rock.

A model for porous rock damage due to retention in deep filtration during injection of water containing solid particles is formulated. The model contains two empirical functions that affect loss of injectivity - filtration coefficient and damage coefficient versus deposited particle concentration.

We show how to solve the inverse problem for determining the first function based on effluent particle concentration measurements in coreflood tests.

The second inverse problem is the determination of the formation damage coefficient from the pressure drop history on a core. These two methods allow determining from laboratory tests the information necessary for prediction of well impairment.
Production Improvement for Horizontal Wells in Sumatra
Authors: Gunarto Ronny , Tran Thanh B. , Widyantoro Barkah , Kritzler Torsten
Published: December 2007

Several horizontal wells have been drilled in different sandstone formations in Sumatra. These formations have a typical permeability of 100 to 500 md, a low bottomhole pressure (BHP) of 450 to 750 psi, and a bottomhole temperature (BHT) of approximately 200°F. The wells are completed with perforated liner. The objective of the horizontal drilling program was to increase oil recovery in low-permeability estuarine reservoirs. Some of the drilled horizontal wells did not perform to expectations and an intensive study was undertaken to identify completion and stimulation opportunities to increase production.

During this study, all aspects of the initial completions were examined and redesigned. The drill-in mud was reformulated to reduce the amount of polymer and increase the use of fine calcium carbonate to decrease lost circulation during drilling and simplify the removal of filter cake during initial completion.Core tests were performed to identify the optimum fluid formulation, which dissolves the remaining filter cake but does not destroy the formation's natural permeability.A new way of removing the filter cake after completing the well was introduced using oxidizer technology.A new, true fluidic oscillator was used to remove near-wellbore skin (in conjunction with an improved acid system) for wells that have been producing for several months or years.

The paper presents several case histories to discuss how completion and stimulation problems were systematically evaluated resulting in increased horizontal well production.
Convective Heat Transfer in Turbulent Flow: Effect of Packer Fluids on Predicting Flowing Well Surface Temperatures
Authors: Vollmer Daniel P. , Fang C. S. , Ortego Anne M. , Lemoine Emile
Published: December 2007

A flowing well continuously looses heat to its surroundings. An accurate prediction for the flowing surface temperature is necessary for production operations. Above optimum surface temperature, chillers are required to cool the gas prior to flowing in pipelines. Too cold of a surface temperature can cause precipitation problems that restrict flow and may require an insulating packer fluid. Economic justification must be decided based on the increased flowing surface temperature that an insulating packer fluid can provide above a conventional one. Therefore, a predictive model was developed that can accurately predict the surface temperature for a flowing well for any Newtonian fluid. The model predicted the flowing well surface temperature (FWST) within 5°F of the measured temperature for the wells studied.

The uniqueness of this model is that a newly derived equation is used to predict the velocity of the packer fluid along the tubing wall caused by free convection for a vertical annulus. Laminar or turbulent flow can be determined from this velocity. In turbulent flow, a friction factor for flat plate or pipe flow must be used to insure accurate predictions. Only when the thickness of the boundary layer equals the midpoint within the annulus can friction factors from pipe flow be used. The model showed how the addition of friction reducers can decrease a well&s flowing surface temperature due to the increase in free convection, i.e., by up to 17°F for one case.
Characterization of Crosslinked Gel Kinetics and Gel Strength Using NMR
Authors: Romero-Zeron Laura , Manalo F. , Kantzas A.
Published: December 2007

Highly crosslinked gels are used in high-permeability reservoirs to achieve good fluid-loss control during well completion and workover operations. Crosslinked gels are also commonly used for shutting off unwanted gas and/or water influx into production wells, and for improving the conformance of the near wellbore injection profile in naturally fractured or in high-permeability reservoirs. In all such applications, the appropriate design of the gel treatment is critical to ensure an efficient gel placement. One important variable of the gel application design is the rheology of the gel system for establishing the crosslinking kinetics and the gel strength after gelation is complete.

Rheology of gels and gelation rates are commonly determined by rheological methods or in a qualitative mode through bottle testing using a well-known gel strength code (i.e., the Sydansk&s Code). The rheological measurements can be both time consuming and expensive, while bottle testing can lead to an inconsistent gel description as a result of the subjective nature of the gel strength code. This paper describes the use of low field nuclear magnetic resonance (NMR0 to monitor gelation rates and to characterize gel strength. This technique provides fast and accurate gel strength characterization and gelation monitoring. Through calibration with polymer concentration, crosslinker concentration, aging of gels, and the effect of brine, it is possible to predict NMR parameters. This then allows for a standardized method for the rheological categorization of gels.

The results of this work present the correlation between the NMR spectra, rheological measurements, and the qualitative codification of gel strength.
Formation Damage Due To Simultaneous Sulfur and Asphaltene Deposition
Authors: Shedid Shedid A. , Zekri Abdulrazag Y.
Published: December 2007

Although many oil reservoirs are producing crude oils of different sulfur and asphaltene contents, deposition problems of sulfur and asphaltene components in porous media were investigated separately. The major objectives of this laboratory study are to investigate the simultaneous deposition of sulfur and asphaltene in porous media. To achieve these objectives, the influences of (1) crude oil flow rate, (2) reservoir rock permeability through which crude oil flows and (3) concentrations of sulfur and asphaltene in the crude oil, on permeability damage of the reservoir rock were experimentally investigated.

Ten dynamic flow experiments were carried-out using different crude oils of different sulfur and asphaltene concentrations and under different flow rates. The crude oil was flooded through different rock permeability of 2.34, 6.23, 16.58, and 21.48 md and under different flow rates of 0.5, 1.0, 2.0, and 3.0 cc/min, respectively. The results indicated that the increase of flow rate increases the formation damage due to simultaneous deposition of sulfur and asphaltene in the reservoir rock. Core samples of lower permeability showed more severe permeability damage than that ones of higher permeability, for the same applied flow rate and the same sulfur and asphaltene content of the crude oil. Furthermore, the increase of asphaltene and/or sulfur content of the crude oil increases the rock damage.

The attained results of this study enlightened the important role of formation damage of carbonate oil reservoirs containing oils of considerable amount of sulfur and asphaltene. In addition, the study provides two empirical correlations capable to predict the permeability damage rate as a function of flow rate, or initial rock permeability. These correlations represent useful tools for semi-analytical and simulation studies.

Introduction and Review

Almost all deep sour gas reservoirs and many oil reservoirs contain elemental sulfur as a dissolved species in virtually. Reduction in pressure and temperature induced sulfur precipitation by a reduction in the solubility of the sulfur in the gas and/or oil phase beyond its thermodynamic saturation point. These changes occur during production operations and can result in sulfur deposition in the reservoir, wellbore and surface facilities. Deposition of elemental sulfur in the near well bore area may significantly reduce the inflow performance of sour-gas wells. In addition, oil reservoirs all over the world suffer of simultaneous sulfur and asphaltene deposition problems in porous media and cause problems in production facilities. Investigation of sulfur deposition in porous media has little attention while asphaltene nature and deposition in porous media has been covered extensively. Furthermore, the investigation of simultaneous sulfur and asphaltene deposition has not been studied in spite of the expected problems of formation damage and facility corrosion.
Fracture Flow Modeling and Visualization
Authors: Augustine Jody R.
Published: December 2007

Many questions relative to fracture flow characteristics remain under investigated. How big does a fracture need to be? How can fines migration potential be alleviated with a fracture? What is the fracture production contribution versus the radial contribution? How much production is directed through out-of-phase perforations? How close can the fracture be to an aquifer?

A three dimensional radial reservoir model was developed to answer these questions. The model integrates the reservoir, wellbore, formation damage, fracture, and the completion hardware.

Historically, researchers have modeled the fracture as one dimensional. By modeling the fracture in 2 and 3 dimensions one can visualize the flow patterns around a fractured well. By analyzing these flow patterns, one can better understand the impacts the fracture is having. Results are presented (both vector and contour plots) that highlight the flows within and around the fracture. Conclusions are presented that quantify fracture effectiveness vs. length and comparisons are made to previous work.
Near-Wellbore Formation Damage Effects On Well Performance - A Comparison Between Underbalanced And Overbalanced Drilling
Authors: Ding Y. , Herzhaft B. , Renard G.
Published: December 2007

Prediction of formation damage that occurs while drilling horizontal wells is a critical point for optimising an oil field development. The economic impact of near wellbore drilling-induced damage and clean up efficiency has led to make significant progress in both experimental and numerical studies in order to assess wellbore flow properties during oil production. As a result, a numerical model has been developed to study the impact of various parameters related to the properties of drilling fluids on the well inflow performance.

This paper describes a numerical approach developed in this model to simulate near wellbore formation damage due to underbalanced (UBD). It is generally expected that UBD will be of benefit from preventing formation damage. However, this benefit can be lost for various reasons. For instance, an overbalanced pressure can be applied on the formation during short periods of time for various operational reasons and it can cause a severe formation damage due to the absence of external cake protection and huge filtrate invasion. Another possible cause of formation damage in UBD is related to spontaneous imbibition which induces water blocking, experienced while drilling tight gas reservoirs.

A methodology for the modelling of possible formation damage during UBD is presented. Cross flow phenomena due to spontaneous imbibition is taken into account to model the filtrate invasion from the well to the porous media as the well is producing.
Impact Assessment and Benthic Recruitment Following Exploration Drilling in the South Caspian Sea
Authors: Tait R. D. , Maxon C. L. , Parr T. D. , Newton F. C. , Hardin J. L.
Published: December 2007

Pre- and post-drilling environmental studies were conducted around an exploration well drilled in the south Caspian Sea in a water depth of 145 m using both water-based and synthetic-based drilling muds. Eight months after completion of the well, chemical analyses of surface sediment samples for linear alpha olefins, polycyclic aromatic hydrocarbons, saturated hydrocarbons, and selected metals confirmed that the spatial extent of the settled cuttings and mud was limited to an approximate 400-m radius.

Cross-sectional photographic images of the seafloor showed significant oxygen demand and presence of sulfidic sediments within 50 m of the well. Coincident benthic samples were examined for total infaunal abundance, species richness, biomass, and distribution of major taxa. The macrofaunal groups Amphipoda, Cumacea and Gastropoda were present in pre-drilling and post-drilling reference samples, but were not present in post-drilling samples collected within 50 m of the well. However, these groups had enhanced abundances, likely in response to moderate organic enrichment at 200 and 400 m distances, where there was no evidence of excessive oxygen demand. Ostracod crustaceans were rare in pre-drilling samples, but were the most abundant post-drilling group in all sediments collected within 400 m of the well site, indicating that elevated organic matter may be a strong macrofaunal attractor. Overall results indicate that changes in sediment chemical concentrations and benthic community composition associated with drilling did not extend significantly beyond 400 m from the well site, and that recolonization of the site was underway, eight months after completion of the well.
A Method to Calculate the Gas-Lift System Efficiency
Authors: Yonghui Liu , Yingchuan Li , Sanwei Liu , Hai Wang , xiaoqi Li
Published: December 2007

The gas-lift system is comprised of gas-lift pumping plant, gas distribution network, gas-lift well, and pipes between gas-lift well and metering station. Each part will affect the others work. Therefore, only when each part works well, the system efficiency would be high. What's more, Rod pump unit has a series of methods to calculate the efficiency, but research on the efficiency of gas-lift system is not available. So it is in trouble in accurately valuing the measures taken to improve the system efficiency. This study also helps engineers find the energy loss and take aimed measures to enhance the efficiency of gas-lift system.
Silica Scale Inhibition for Steam Generation in OTSG Boiler
Authors: Pedenaud Pierre , Goulay Caroline , Pottier Fabien , Garnier Olivier , Gauthier Bernard
Published: December 2007

The production of extra heavy oil or bitumen using the SAGD method (Steam Assisted Gravity Drainage) entails the generation and injection of a large quantity of steam into the reservoir. A similar quantity of hot water is produced together with the oil. Taking into consideration environmental regulations, it is probable that partial or even total recycling of the produced water into steam will be required.

After circulating in the ground production water may contain high concentrations of silica (up to 400 mg/l). Silica removal is very expensive in terms of investment and operating costs. The risk of silica salt deposition in the boiler tubes becomes significant when the silica content in the feed water exceeds 100 mg/l (OTSG boiler supplier specifications). Deposition of silica increases local thermal resistance and can lead to tube failure. The silica removal process is also an environmental issue owing to the production of sludge.

This paper demonstrates that silica scale inhibitors can be used in steam generation in an OTSG boiler. The original laboratory test program and results obtained are presented. Test results were corroborated on an industrial OTSG boiler in operating conditions. Results show that use of silica scale inhibitors instead of silica removal could generate substantial savings in cost.
Optimization of Perforated Completions for Horizontal wells in a High-Permeability, Thin Oil Zone. Case Study: Hassi R'mel Oil Rim, Algeria
Authors: Bourenane Mahdi , Tiab Djebbar , Recham Reda
Published: December 2007

A considerable number of studies have been conducted to optimize the perforated completions for horizontal wells, but very few of them took into account the effect of reservoir heterogeneity and coning problems in the completion design. One of the most relevant work directly related to this topic is the one developed by Goode and Wilkinson7. They have presented an analytical solution for the performance of partially completed horizontal well. Their model, however, has two major limitations: (1) it considers the reservoir as homogeneous and ignores heterogeneity, and (2) it does not take into account the water and gas coning effects.

In this study, a numerical solution has been developed to optimize the perforated completions for horizontal wells in a heterogeneous reservoir laying between a large gas cap and an active aquifer (double coning problem). Another objective of this study was to examine the performance of various perforation schemes for horizontal wells in Hassi R'mel oil Rim using reservoir simulation. Since the capability of the numerical simulators to model a horizontal well performance is largely controlled by the quality of the geological description of the reservoir, therefore, a reservoir characterization based on geological (sedimentary) units was performed on the A-Sand reservoir of Hassi R'mel oil Rim.

The simulation modeling in this study was undertaken in two large parts. First, a sensitivity analysis was conducted to investigate the effects of the most relevant reservoir parameters on the horizontal well performance for different perforation schemes. This allowed us to examine the effect of the perforation length and its distribution and to find the optimum perforation scheme for horizontal wells in Hassi R'mel oil Rim. Second, the simulation modeling was involved in a real case where the performance of the well HRZ-09 was a concern. The reason for taking this well as a case study is that it was completed non-conventionally using the Inverted High Angle technique. This completion led us to investigate the possibility of perforating the slanted section of the well, in addition to the horizontal section (Double perforation scheme).

As a result of this study, correlation curves have been generated to optimize the perforated completions for horizontal wells in Hassi R'mel oil Rim. It has also been found that the optimum perforation scheme for horizontal wells in Hassi R'mel oil Rim corresponds to the case of 60% uniformly distributed perforation. From the case study, it was found that there is no extra-recovery to be expected from the double perforation of the well HRZ-09. Moreover, such perforation scheme yields much higher gas-oil ratio in comparison to the actual perforation case. This result was confirmed by an economic analysis performed on three proposed perforation schemes.
Technology Mastery - Foundation for Technical Specialists
Authors: Nor Rosly Mohd , Kario Mohamed Wahid , Kosuma Christine G
Published: December 2007

Global uncertainty and heavy competition require E&P companies to remain effective in investments and prudent in people development. These challenges compel us to have a learning system that links to business objectives and enables effective knowledge transfers. This paper outlines a structured learning framework which is a competency-based system that links learning objectives to desired business results and establishes a mechanism for identifying, developing, measuring and tracking individual competencies and capabilities.

The Technology Mastery Program is part of an integrated program, which covered data, processes, tool and people as the heart of the program. It is to maximize the return on investment in technology, reduce interpretation cycle time, enhance the workflow application, improve quality of the result and decision-making.

The structure uses a credit-based system to monitor and measure technical competencies through accreditation of technical skills. The learning curriculum is built to facilitate cross training by offering broad-based competencies in multiple disciplines. The learning sequence complements the methodology by providing web-based training before, and after the course, immediate application in the current work, mentoring, and assessment. The process addresses common problems that occur with many training programs including timeliness, relevancy, transfer of skills to the job, and learner accountability for results.

People can accelerate their acquisition of technical knowledge and increase professional development in this selfdriven framework. Furthermore, the program is aligned to meet the requirements that lead to the specialist technical ladder which was recently introduced in the company.

The program was conducted in stages commencing midAugust 1999 and has proven to be very successful. It is currently in its third stage and as each stage progressed, new disciplines were added and program upgrades made based on lessons learnt. As of June 2003, one hundred and eighty five staffs from Geology, Geophysics, Formation Evaluation, Reservoir Engineering, Production Technology and Petroleum Economics have enrolled into this program. They are working either in exploration, development or production based projects and have benefited from this program, which resulted in reserves addition, and profitability of the company.
Pipeline Integrity Management System - A New Approach In Managing Pipelines
Authors: Abd Satar Fairudul Azhar , Raja Ismail Raja Zahirudin , Saidin Khairul Taufiq
Published: December 2007

Managing pipelines in operation divisions of PETRONAS Carigali Sdn Bhd (PCSB) always as important as producing a hydrocarbon from its fields. Three (3) PCSB domestic operation regions namely Peninsular Malaysia Operation (PMO), Sarawak Operation (SKO) and Sabah Operation (SBO) are currently operating a total of more than 277 pipelines. Due to aging pipelines that PCSB are currently operating in which some are more than 25 years, a prudent management in term of its risk and consequence as well as cost of operating the aging pipelines need to be re-assessed via a comprehensive management system that can be used as a tool to inform PCSB management in term its integrity.

It is imperative that an integrated pipeline integrity management system (PIMS) to be made available to ensure pipelines integrity always available upon request and are up to date with the latest integrity status. Before the development of the PIMS for PCSB, all the pipeline integrity management for each region is residing with the individual(s)/units that performing specific functions e.g. inspection, engineering and operations. With the development of the PIMS, all those effort related to pipeline integrity are managed and integrated in more effective manner by single point reference i.e. Pipeline Competent Person in PCSB. It was determined that the adoption of an integrated approach in managing pipelines would be the optimal way to facilitate prudent management and surveillance of pipeline integrity.

The purpose of this paper is to discuss the effort that had been put in making the PIMS project materialised as well as to share the experience in developing the system with the help of other resources from internal and external of PCSB organisation.

Having the PIMS implemented in PCSB it will reduce considerable amount of time and effort that previously needed to acquire the integrity status of pipelines. Adopting an integrated team effort throughout the company has provided the necessary forum for open and inter-disciplinary exchange of ideas and experiences on PIMS related matters. As a result, it has aided in enhancing cooperative actions and the capturing of synergism, all to the benefit of the PCSB.
Quantitative Evaluation of Information Loss in Reservoir Upscaling
Authors: Qi Dasheng , Hesketh Tim
Published: December 2007

Upscaling technique has become an increasingly important tool in recent years for converting highly detailed geological models of reservoir to simulation grids. However, how to qualify the upscaling results, i.e. whether an upscaled results provides a good or bad approximation, is one of the outstanding problems remained in this research field.

Comparing the simulation results for the reservoir before and after scale-up is direct and adaptable. But the shortcoming is the simulation results of the original fine model is too costly even can not be obtained. This paper evaluates the characteristics of information loss in reservoir upscaling and proposes two new indicators of information loss, ILIa and ILIb. Based on information loss, a method- independent technique for evaluating upscaling results in reservoir engineering is proposed. The new validation method can be used to evaluate the upscaling results before simulation stage.
Bokor Field Redevelopment—A Brown Field Integrated Modeling Workflow Case Study
Authors: Flew Stephen , Mulcahy Matthew , Stelzer Hermann , Boitel Alain , Zainuddin Faizal , Harun Abd Rahman , Hassan Zulkarnain , Aziz Kamaroll Zaman A.
Published: December 2007

After more than 20 years of production, the 800 million STB Bokor field, offshore Sarawak, Malaysia, is set to undergo a revitalization to increase production rates and recovery factors. A joint PETRONAS Carigali (PCSB)-Schlumberger team was formed to review the field and develop the first full field simulation model, which will be utilized as a 'live' model for identifying further potential and for future reviews. This paper outlines the modeling workflow and processes developed to allow the study to be completed within a shorter duration than with a conventional approach, as well as the key study results.

Made up of some 130 vertically stacked reservoirs over a 6,000-ft interval, evaluation of the field is hampered by the lack of any useful seismic images over the hydrocarbon zone, owing to shallow gas and other anomalies. Understanding the reservoir behaviour has always been a challenge, with the degree of sand consolidation in the reservoirs varying from totally unconsolidated at 1,500 ft subsea, filled with 10 cP oil, to consolidated deeper sands, with 0.1 cP oil at 7,500 ft subsea. In addition, the limited pressure depletion owing to the presence of a very strong aquifer, and the fact that many fluid contacts have not been penetrated, means that significant uncertainty still exists over the likely stock-tank oil initially in place (STOIIP).

By fully utilising all available data and an iterative team-based approach to history-matching the geostatistical models with production data, an understanding of the key parameters was gained. This revealed that in many reservoirs, what was previously considered poor-quality rock was in fact a major contributor to reservoir flow, being neither as poor in permeability nor as high in water saturation as previous interpretations suggested.

Through the increased understanding gained during the review, robust predictions have allowed new facilities to be appropriately sized, allowing the field to begin its new lease of life.