bluuebunny/crossref_metadata_2025 huggingface dataset:
The Development and Successful Field Use of Viscoelastic Surfactant-based Diverting Agents for Acid Stimulation
Authors: Alleman David , Qi Qu , Keck Richard
Published: December 2007

The success of a stimulation treatment or gravel packed completion is often dependent on the ability of the diverting agent to force the acid treatment into different portions of the reservoir. Diversion of acid treatments in the Gulf of Mexico (GOM) have been predominately accomplished by using either foam, HEC, or particulate matters to "temporarily" block off the zones and force the acid elsewhere. Recently, viscoelastic surfactant based diverting agent has been successfully used in acid stimulation in GOM. The fluid generated its viscosity through the densely packed surfactant aggregations, called vesicles. Normally, densely packed conventional surfactant vesicles require high concentration of surfactant to generate adequate viscosity. A new fluid was developed by incorporating a polyelectrolyte with the surfactant to facilitate the vesicle formation, to reduce surfactant concentration and to enhance thermal stability of the fluid. The rheological properties of the fluid can be adjusted by fluid pH, surfactant concentration, and properties of polyelectrolyte and temperature. An internal breaker package was developed to break the surfactant gel and reduce the fluid viscosity to that of water at the desired time and temperature. This system does not require contact with formation fluids, brines, or acids for clean up to provide optimum production. The Core tests were performed and the results demonstrated that there is no formation damage observed in treated core. This paper describes the fluid properties at various pH's, surfactant and polyelectrolyte concentrations, temperatures, internal breaker loading, and salt concentrations along with two successful case histories.
Field Cases of a Zero Damaging Stimulation and Diversion Fluid from the Carbonate Formations in North Kuwait
Authors: Al-Mutawa Majdi , Al-Anzi Ealian , Ravula Chakravartha , Al Jalahmah Faisal , Jemmali Mohammed , Samuel Elsamma , Samuel Mathew
Published: December 2007

The high permeability contrast seen in the producing zones of the oil wells of North Kuwait Mauddud formation makes the uniform stimulation of this carbonate formation a challenge. To achieve diversion, polymer based fluids were used earlier, but with limited success. Recently, a non-polymeric system containing a Visco-Elastic Surfactant based Self Diverting Acid (VES-SDA) was used to divert and effectively stimulate these pay zones.

Production logs run before and after the stimulation treatments indicates stimulation of the entire perforated intervals. Stimulation using this new system on the first 17 wells resulted in a production increase of about 30,000 BOPD, much higher than that expected from conventional treatments. The wells that were not producing earlier after several conventional treatments are now producing naturally after treatments using this non-damaging system.
Guar Gum Degradation: A Kinetic Study
Authors: Weaver Jim , Gdanski Rick , Karcher Arron
Published: December 2007

Guar gum is a naturally occurring polysaccharide that is used extensively as a water-based viscosifier. It is the principle agent used to manufacture viscoelastic fracturing fluids. It is composed of the simple sugars galactose and mannose in a ratio of approximately 1:1.6.

Guar is a linear polymer with a backbone composed of mannose connected by β-1,4 acetal linkages. This backbone has single-unit branches of galactose connected by α-1,6 acetal linkages. The ratio of mannose to galactose has been shown to influence the solubility of the guar gum. As the galactose content is reduced, the solubility of the polymer in water decreases dramatically. Low-galactose polymers, such as locust bean gum, have very low solubility in water.

The viscosity of guar gum-based fracturing fluids is reduced at the end of a fracturing treatment to promote fluid recovery rates. To reduce the viscosity, several materials are used as gel breakers. Most of these materials cause the degradation of the polymer by hydrolysis of the acetal linkage. However, two types of acetal linkages in guar are available for hydrolysis. Hydrolysis of the backbone β-1,4 acetal linkage results in large changes in molecular weight and fluid viscosity. Competing hydrolysis of the side-chain α-1,6 acetal linkage results in the removal of galactose branches that have little impact on the molecular weight but significant impact on solubility.

This paper presents kinetic, viscosity, and solubility data that demonstrate the importance of acetal hydrolysis in the chemistry of guar degradation. Additionally, rate expressions that can be used to influence gel breaker design and well flowback programs are presented.
Development of a Nonresidue Polymer-Based Fracturing Fluid
Authors: Wang Xiaolan , Qi Qu
Published: December 2007

Good fracture conductivity is essential to the success of fracturing operations. It has become an important aspect in the development of fracturing fluid technology. To improve proppant conductivity, fracturing fluid systems with reduced polymer concentration have been developed. While reduced polymer concentration would result in less polymer residue upon polymer broken, the insoluble polymer residue generated from the broken polymer still causes blockage of generated conductive channels and a decrease in the formation production rate. Alternatively, a non-polymer fracturing fluid, i.e., a viscoelastic surfactant system has been developed in an effort to allow fracturing of a well with less formation damage. Although the absence of polymer residue presents fewer problems for fracture clean-up as compared to polymer based fracturing fluids, one disadvantage associated with such viscoelastic system relates to their ineffectiveness when applied to high permeability formations. In addition, the cost of surfactant based fracturing fluids is high.

This paper highlights research work of a new polymer based fracturing fluid system. This fracturing fluid system utilizes an innovative polymer that would generate minimal or no residue upon being broken, thereby causing less damage to the formation and proppant bed. Laboratory testing has shown that this fracturing fluid system can provide efficient viscosity with 20 pounds polymer per one thousand gallon at about 200°F. Stim-Lab testing data of a certain formulation of such fracturing fluid display excellent retained conductivity of proppant bed.
Scale Control in a Hydrogen Sulfide Treatment Program
Authors: Sitz C. D. , Barbin D. K. , Hampton B. J.
Published: December 2007

Mineral scales are a common occurrence in hydrocarbon production systems. Oilfield brines contain varying amounts of dissolved solids that can precipitate during production because of changes in temperature, pressure, brine pH or brine composition.

In addition to deposition due to physical changes in the produced fluids, scale can form because of the interactions of the brine with treating chemicals used in the system. An example is found in the case of some hydrogen sulfide scavengers.

Hydrogen sulfide, H2S, can be efficiently removed from produced brine and gas using a variety of methods. In the oilfield, the most commonly applied H2S scavenging chemistries are the amine aldehyde condensates. While this type of chemistry is very effective in H2S removal, a significant increase in brine pH is an unfortunate side effect. In cases where the brine contains high calcium concentrations, large amounts of calcium-containing scale can form, restricting flowlines, valves, general hardware and valve soft goods.

This paper discusses steps taken to eliminate severe scale deposition problems resulting from a hydrogen sulfide scavenger treating program on production platforms in the Gulf of Mexico. Previous attempts to control scale caused by H2S scavengers have included brine pH reduction by the addition of acids and scale inhibition treatment programs. However, the treatment requirements specified for the locations precluded the use of traditional remedies and led to the development of a novel approach that gave positive results far exceeding expectations.
Mechanism Of Crude Oil/Water Interface Destabilization By Silicone Demulsifiers
Authors: Noïk Ch. , Dalmazzone Ch. , Komunjer L.
Published: December 2007

Oil exploitation is always accompanied by non-desired formation of emulsions due to the presence of naturally occurring surface-active molecules such as asphaltenes and resins. Their presence stabilizes the oil/water interface and therefore, it is necessary to break the emulsions by adding other surface-active molecules. Formulations based on polysiloxane molecules were selected as effective non-toxic products to enhance the oil/water phase separation. Relations between the efficiency of formulations and the interfacial properties of silicone molecules are the objective of this study. Formulation selection is based on bottle tests using turbidimetric measurements and on dynamic tests using a "dispersion rig" set-up. This experimental set-up permitted to reconstitute emulsions under pressure and temperature conditions and then to inject additives into the formed emulsion online. Rapid kinetics of separation as high levels of separated water were observed. Dynamic interfacial measurements were performed using complementary techniques. Drop volume technique allowed to measure the evolution of crude oil/water interfacial tension with time. Langmuir trough technique permitted to obtain two-dimensional compression isotherms as well as the measurement of elastic properties of interfaces. The coalescence of water droplets leading to the destabilization of emulsions and consequently to the water/oil separation efficiency could be related to the rheological properties of water/crude oil interface. Therefore, such comprehensive study based on a specific methodology can lead to a strict and effective selection of emulsion breaker additives in relation with the oil composition.
Determination of Foam Induced Fluid Partitioning in Porous Media using X-ray Computed Tomography
Authors: Nguyen Quoc P. , Currie Peter K. , Zitha Pacelli L.J.
Published: December 2007

Foam is used during matrix stimulation to promote the diversion of acid from the (undamaged) high permeability streaks to the (damaged) low permeability ones. Often foam is first placed in the formation, near the wellbore, and then acid is injected. Diversion is obtained from the strong reduction of liquid and gas mobility, associated with the formation of foam films.

In this paper, foam flow in porous media has been investigated under conditions that are relevant for acid diversion induced by foam. First, a simple model for foam placement and liquid injection following foam has been developed. Then core flood experiments were conducted using Bentheim (quasi-homogeneous) and Berea (heterogeneous) sandstone cores, and nitrogen (N2) foam stabilized with sodium dodecyl sulfonate (SDS). The pressure drops over several core sections were mornitored as a function of time. In addition, the fluid partitioning was determined in real time using the X-ray computed tomography (CT) during the core floods.

The experiments using quasi-homogeneous cores show that flow in a core containing surfactant solution (placement) exhibits a front-like pattern. An unexpected secondary liquid desaturation, which becomes dominant after foam breakthrough, has also been observed. The injected liquid following foam develops into a stable finger. In the heterogeneous porous medium a fingering pattern, controlled by the heterogeneity features of the core, develops during foam flow in the presence of surfactant. Liquid desaturation appears to be relatively stronger, but the final liquid saturation remains higher than for the homogeneous cores. Also the injected liquid displays a complicated fingering pattern. Trapped gas finally is estimated to be 70 and 60% for the homogeneous and heterogeneous cases, respectively. These observations have been successfully interpreted using the proposed model.
The Use of Flow Models in Assessing the Risk of Scale Damage
Authors: Mackay E. J. , Graham G. M.
Published: December 2007

The advent of subsea wells, production from ever-deeper waters, and the resulting increase in value of wells and downhole equipment means that more effort is being put into assessing the risks posed by potential scale formation. This is required not only because of the increasing value of the investment that needs to be protected, but also due to the increasing difficulty in accessing wells to treat them. It is becoming widely recognized that an integral part of the scale risk assessment process involves calculating fluid flow in the reservoir. These calculations enable the operator to identify where in the reservoir scale may form, how these zones develop as a function of time, and where they are located relative to the production wells. If scale forms deep within the reservoir, then typically there is no loss of productivity, and indeed the effect is beneficial in that it reduces the scaling potential at the production wells. However, if scale deposition should be expected close to the production wells, then steps should be taken to mitigate any harmful effects. The choice of management strategy will depend on the type and severity of the scaling problem, and the access to the wells requiring protection.

A range of flow simulation tools is studied. These vary from standard finite difference reservoir simulators to streamline models designed specifically to track the flow path of injected waters, to more complex fluid flow and chemical reaction models capable of calculating scale precipitation reactions and the subsequent impact on porosity and permeability. Field examples are then given of situations in which these models have been applied, and the implications for scale management of the resulting calculations are discussed.
Ferrous Sulfide Solid Formation and Inhibition at Oxidation-Reduction Potentials and Scaling Indices Like Those That Occur in the Oil Field
Authors: Przybylinski John L.
Published: December 2007

Ferrous sulfide deposition is a significant oilfield problem that has not been studied extensively, partly because of the difficulty in studying it under the reducing conditions found in the oilfield, partly because of a perception that its formation can not be controlled using current technology, and partly because of a perception that it is easy to remove when it does form. The difficulties in studying it may be overcome with careful work, and the perceptions are not entirely accurate.

Ferrous sulfide is not a single entity; it exists in numerous solid forms. One of the determinants of the form taken by the solid is the oxidation-reduction potential of the system. This paper discusses precautions that need to be taken when conducting studies under reducing conditions.

The paper presents laboratory data obtained at defined oxidation-reduction potential and pH. It shows how the deposition of ferrous sulfides may be reduced significantly using chemicals at mg/L levels.
Comparative Study of Asphaltene Adsorption on Formation Rocks under Static and Dynamic Conditions
Authors: Rayes B. H. , Pernyeszi T. , Lakatos I. , Tóth J.
Published: December 2007

Specific adsorption of asphaltene from light, medium and heavy oils were determined on reservoir rocks having different calcite and clay contents. Pure calcium carbonate and montmorillonite were used as a basis of comparison. Static and dynamic asphaltene adsorption tests were performed for comparison. The dynamic tests were carried out on crushed reservoir rocks. The batch type measurements served for determination of the adsorption isotherms and kinetics of sorption. The effect of asphaltene adsorption on wettability was also investigated by contact angle measurements on homogeneous and heterogeneous rock plates.

Based on the experimental results it was concluded that there is no significant difference in the adsorption of different asphaltenes: depending on the mineralogical composition the adsorbed amount changed between 2 and 5 mg/g (18 and 45 mg/m2). A well-defined correlation was obtained for the effect of calcite and montmorillonite: the adsorbed amount increased with the clay content, while the carbonate content decreased the adsorption loss. Under static conditions, the adsorption of asphaltenes in low concentration range could be described by the Langmuir and the Tóth isotherms, while in the high concentration ranges the declining trend of isotherms suggests a competitive process. The existence of competitive and consecutive processes is well demonstrated by the cumulative curve of adsorbed amount obtained by dynamic adsorption tests. The experimental results proved the composite, multicomponent character of the asphaltenes and the role of asphaltene concentration in the wettability alteration process.
Integrated Reservoir Simulation Studies to Optimize Recovery from a Carbonate Reservoir
Authors: Gharbi Ridha B. C.
Published: December 2007

A three-dimensional finite-difference reservoir simulator, integrated in an EOR expert system, has been used to determine the reservoir management and production strategies to optimize the oil recovery from a carbonate reservoir. The reservoir is a candidate for an EOR process or otherwise subject to abandonment. After screening the reservoir for an appropriate EOR process on the basis of its properties, it was determined that miscible carbon-dioxide injection is the most suitable process. The management strategies involved studying different design parameters to maximize the project profitability. The injection techniques that were tested in this study include: (1) water-alternating-gas (WAG), (2) simultaneous water-alternating-gas (SWAG) injection, and gas injection in the bottom of the reservoir with water injection in the reservoir top. All simulation runs were conducted using permeability fields that have been conditioned with core data taken from wells in the field. Specific strategy that was used includes the use of horizontal injectors in conjunction with vertical producers. This well configuration has been shown to yield the best oil recovery compared to other well configurations. Simulation results show that the most economical method to produce this reservoir was to simultaneously inject water at the reservoir top and gas at the reservoir bottom. This production strategy has resulted in better sweep efficiency and therefore high oil recovery and good economics.
Application of Bridging Theory on Saucier Gravel to Examine the Sand Control Effect
Authors: Xiang Wentao , Wang Pingshuang
Published: December 2007

Gravel packing is one of the sand control techniques effectively used in oilfields with unconsolidated formation. The technique most widely used for selecting a suitable sized gravel to control the production of formation sand was developed by Saucier. With this technique, however, no consideration is given to the size distribution of the formation sand sample, which probably results in failure in sand control. This paper reviews the technique outlined by Saucier, and then the bridging theory as well as an empirical formula for packed particles is applied here to examine the sand control effect of the gravel chosen with Saucier formula. An offshore case in China is also presented to illustrate the effect. The analysis will be helpful in gravel packing design.
First of Kind Self Erecting Tender Rig Combines Performance and Safety
Authors: Krueger Philip J. , Leland Anders
Published: December 2007

The drilling of minimum cost development wells in the Gulf of Thailand (GOT) requires a drilling philosophy based on continuous improvement. Adherance to this philosophy has yielded some of the fastest drilling times in the world. This performance is due in part to the ability to plan and drill 12 to 16 well platforms instead of "one-off" wells, a concept that has been fundamental to building efficiency. To rig up on a platform ready to drill 16 wells requires a great deal of teamwork and up-front planning between the asset teams and the drilling group. To drill minimumn cost wells, key contractors and service companies must be aligned with the common goal of efficient and safe operations. Drilling rigs, tools, and equipment are constantly being upgraded and redesigned to be fit for purpose to the conditions encountered in the GOT.

In 2001 Smedvig's Self Erecting Tender Rig (SETR) T-7 was at the end of a five year contract with Unocal Thailand. The T-7 had been under continuous contract in the Gulf of Thailand since it was first commissioned in 1981 and was scheduled for dry docking as part of the ABS classification process. Unocal and Smedvig saw an opportunity to evaluate upgrades to the barge and derrick set (DES) with the goal of improving drilling efficiency and HES performance. It was believed that the best way to work more efficiently while maintaining a safe working environment was to evaluate the drilling unit and make improvements there. A team was then formed to evaluate the drilling unit and the economics of investing capital in the upgrades.

This paper describes:

Description of geographical setting Performance drilling history Project conception and overview Operating company and rig contractor relationship Rig modifications purposes and performance Health Environment and Safety concerns and management
A Novel Method of Assessment of Spurt and Filtrate Related Formation Damage Potential of Drilling and Drilling-in Fluids
Authors: Amanullah Md.
Published: December 2007

Solids as well as the liquid phases of drilling muds invade and interact with reservoir formations that contain oil and gas. These invasion and interactions change the formation permeability and in extreme cases may stop the fluid flow from the reservoir to the wellbore. The damage caused by mud spurt and drilling mud filtrate can influence the log response significantly due to the change in near borehole permeability and displacement of formation fluids by the mud filtrate. This dictates the assessment of the spurt and filtrate related formation damage potential of drilling muds and drill-in fluids to screen and select the best fluid for drilling the reservoir section of the borehole. This paper describes a novel method to highlight the formation damage potential of drilling muds by assessing the erosional characteristics of mudcakes formed by different mud systems.

A unique test procedure and a novel test facility have been developed for experimental determination of mud spurt and filtrate related formation damage potential of different muds and drill-in fluids. The test set up consists of a wooden bridge to fix the mud agitator, an erosion cell for closed loop circulation of eroding fluid, a mud agitator to simulate the hydrodynamic condition of the borehole-drill collar annular section, a lab jack to elevate the erosion cell to a desired height to maintain a constant clearance between the borehole wall (filter paper) and the extreme end of the rotating shaft.

Experimental results indicate significant variations in the erosion coefficients of mudcakes for an identical hydrodynamic condition and clearance between the borehole wall and the end point of a rotating shaft. Cakes formed by several water-based muds were evaluated using the newly developed technique. The results indicate that the presence of electrolyte increases the erosion coefficient of bentonite mudcake and thus significantly increases the damaging potential of bentonite mud. Ionic fluid loss additives such as PAC and CMC reduced the erosion behaviour of salt water-based bentonite mudcake and thus indicate their ability to reduce the spurt and filtrate related formation damage. The presence of non-ionic fluid loss additive ‘modified starch’ shows little improvement of erosional behaviour of salt water-based mudcake and thus indicates severe formation damage potential if the reservoir section is drilled using this type of drilling muds.
Application of Downhole Oil-Water Separation: A Feasibility Study
Authors: Alhoni Mohamed A. , Jerbi Khalid K. , Drawil Taher A. , Zekri Abdulrazag Y.
Published: December 2007

An engineering feasibility study has been conducted on the major operated oil field of waha oil company to determine the feasibility of applying downhole oil/water separation technology (DHOWS) and to rank candidate wells within this field on the basis of their suitability for a DHOWS instalilations. Under operations consistent with the existing field development (or any future developments), the nature of the GE reservoir is such that, the remaining oil reserves will have to be produced at high and constantly increasing watercuts. Downhole separation and disposal of produced water represents a material opportunity to improve the current and future operations of the field.

A screening template was developed to review the reservoir and well characteristics in more details and to identify a list of candidate wells for the possible implementation of DHOWS technology. Several operational risk and concerns exists in respect of the candidate wells were identified. Eighteen wells our of twenty four wells demonstrated favourable reservoir and well characteristics and meet the initial DHOWS screening criteria. The screening template may be used to evaluate other fields for potential conventional DHOWS applications. A preliminary design of a DHOWS application for three wells is presented in this paper.
Innovative Planning and Monitoring Improves Production from an India Offshore Field
Authors: Kumar Adesh , Gupta V. P.
Published: December 2007

Mumbai High field discovered in the year 1974, is located in Western Offshore of India, 160 km South West off Mumbai City. The field was put on production in May 1976. The field achieved a peak production of about 400,000 BOPD during year 1984. To maintain reservoir pressure, suitable water injection scheme was put in place in 1984-85. The field is currently operating on gas lift mode of artificial lift. The field is in now matured stage.

There is a vast gap in demand and supply of hydrocarbons in India. Country import about 66% of its crude oil requirements. Current high rise in prices of crude oil necessitated increased efforts by National Oil Company (ONGC) to enhance production by about 0.5 MMT from the committed targets. Indian offshore being the 70% contributor of domestic crude oil, special focus was accorded to these fields.

Mumbai High being largest field in Offshore, a systematic planning and monitoring of action plan were adhered. To augment the production from this matured field, as a short-term measure, a multi-disciplinary team (MDT) was formed. The team brought out the action plan in August-2000 and implementation started in September-2000. The four types of jobs were planned for Bombay High field viz. Drilling of new development wells, diversion of existing well location to new location by long-drift side-track (LDST), cost effective innovative stimulation jobs, additional perforations in some of the existing producers. All these four types of jobs were carried out within the available resources like drilling rig, stimulation vessel and marine survey unit (MSU). The systematic monitoring of these actions has led to a learning curve for future. In addition to this, some of the wells were taken up for other remedial jobs like surface modifications to reduce backpressure in some well platforms, work-over jobs, scale removal jobs etc. By close monitoring of each well and associated action, the planned additional targets of 0.5 MMT up to March-2001 were achieved.

The present paper describes the details of new development wells drilled using non-damaging drilling mud, diversion of existing well location to new location using the existing slot using LDST, innovative stimulation technique and additional perforations. For each of these activities, a detailed analysis has been made and learning curve drawn for future.
Numerical Modelling of Stress Around a Wellbore
Authors: Chatterjee R. , Mukhopadhyay M.
Published: December 2007

Numerical analyses are carried out to obtain the understanding of stress distribution near and around a drilled circular wellbore into the rock masses. The seven numerical two-dimensional models are generated using the ANSYS finite element software. The models are analysed to investigate the effects of the equal and differential far-field stresses on and around the drilled wellbore, to study the contrast in Young's modulus for rocks inside and outside the welbore as well as to study the effects of fluid pressure during drilling. Stress magnitudes and orientation is varying uniformly around the wellbore under the equal far-field stresses. Differential far-field stresses are the main cause of deformation of stress trajectories. Stress trajectories become elliptical around the wellbore. Differential far-field stresses and contrast in rock strength parameter like, Young's modulus are playing important role in modifying the stress contour pattern near and around the wellbore. The drilling fluid pressures along with the differential far-field stresses affect the change in stress inside as well as outside the wellbore.
Corrosion Management in Production Pipeline Network Using Risk Management Analysis
Authors: Kusumo A. Lesto Prabhancana , Supriyatman Deden , Kristanto Dedy , Prasetia Andi Eka
Published: December 2007

Corrosion management is the integrated corrosion handling, begin with design of facilities, material selection/composition of metal, manufacturing, transportation, installation, operational, monitoring, maintenance and treatment if the specific incident. Risks will happen in early design until maintenance and will resist operation system performance and function. Risk management analysis is a new concept to make planning of operation system that integrated from design, operational until maintenance. This concept integrates Hazard Operability (HAZOP), Fault Tree Analysis, Failure Modes and Effect Analysis, Failure Modes and Effect Critically Analysis, Risk Based Inspection, Risk Centered Maintenance, Risk Based Maintenance and many more. The international standards (such as API, API-STEP, EPA, ISO 9000, ISO 1400, AISI, NACE) completed the integration. Risk management analysis is the part of Integrated Asset Management System (IAMS) that have developed recently in PERTAMINA/PSC/JOB in Indonesia. Corrosion handling using risk management analysis is applicator in production pipeline network of oil and gas industry. Using risk management in corrosion management will get output: make optimal in operation system, minimum effects to personnel and environment, keep equipment quality and performances, also cost efficiency.
A New Method for Evaluating Stimulation Treatments in Carbonate Reservoirs of Saudi Arabia
Authors: Al Qahtani Abdullah M.
Published: December 2007

Acid stimulation treatment has been conducted to restore/improve productivity/injectivity of wells completed in carbonate reservoirs. A Well is generally put on stimulation treatment schedule if a transient pressure test shows a positive formation skin factor. From a production engineering viewpoint, the success of an acid treatment is measured by the magnitude of production rate improvement. Another important factor is the stimulation cost for the amount of production gain. Viewed as such, candidate selection for stimulation plays an important role in the success of a stimulation treatment.

This paper presents a new approach of evaluating stimulation jobs in carbonate reservoirs in Saudi Arabia. A new Type–curve approach is presented to assess the success of a stimulation job in a specific field. This study is supported by analytical and simulated solutions in addition to field statistics. Case studies of success and failures stimulation treatments are presented.

The paper also highlights the economic consideration in stimulation treatments that can influence stimulation decisions.
Successful Extreme Underbalance Perforation In Exploration Well, Donggi Gas Field, Sulawesi
Authors: Halim Andry , Danardatu Heru
Published: December 2007

Donggi Structure is one of the gas field prospected in Banggai Basin, Central Sulawesi. Donggi-1 (DNG-1), which is the first well drill in this field, was drilled in August 14, 2001 and was reached TD at 2498.5 m. The drilling in this well has been successfully done without any major problem and it is + 2 day finished ahead of drilling prediction/program.

Donggi gas field is commonly composed of Carbonate reef (limestone). The lithology of this field sequence from surface down to basement is : Celebes Molase, followed by POH formation (clay with sandstone), Mentawa member (reef of limestone), Minahaki formation (limestone) and Tomori formation (limestone).

To prove the gas prone seeing from logging evaluation after drilling, TCP gun was run by using "Extreme Underbalance Perforation" technique to perforate the well completed with the DST assembly. The gun system is a mechanical release that secures the guns firmly during perforation and avoiding the risk of fishing the tool after the operation. The well is flowing immediately after the perforation which will allow immediate well clean up. Therefore, the well productivity will increase and formation damage will be minimized. In EUB perforation, it is created more than 1000's psi drawdown instead of less than 100's psi in classical perforation.

The EUB application in this well has been successfully flown the gas and condensate during the test and reduced the skin effect and increase the reservoir productivity. It can be seen from the DST-4 and DST-5 analysis result that the skin factor is negative.

The isochronal and pressure build up analysis result in zone-4 is Pr = 2560 Psia, AOFP = 25.1 MMSCFD, skin factor is −1.88 and the radius of investigation is 206 m, and in zone-5 is : Pr = 2540 Psia, skin factor is −4.42, and the radius of investigation is 1593 m.
A New Method for Determination of Gas Reservoir Parameters with Rate Decline Data
Authors: Li M. , Sun L. T. , Li S. L.
Published: December 2007

For the boundary-dominated flow in a gas reservoir producing against constant wellbore pressure, Fraim proved that normalized time VS. rate data traces Arps exponential decline curve. However, it is tiresome to match type-curve when normalized time is introduced. To obtain normalized time, G, a value for original gas in place, is assumed and is then used to calculate normalized time and to match the curve with the Arps’ base b curve closest to the exponential curve. A new value of G is worked out. This process will be repeated several times until convergence is obtained for the exponential decline curve.

Technique developed in this paper provides a rapid and accurate way to analyze rate decline data. Normalized time VS. rate data follows the exponential decline curve, indicating non-linear regression technique can be applied to tackle the problem. Regression technique is used to obtain the exponential decline parameters Di and qi based on which reservoir parameters deteremined with Fraim's technique can be easily derived from formulas presented in the paper. The put technique matches Arps' exponential curve automatically and determines reservoir parameters without type-curve matching . The validation and procedure of the present technique with rate decline data from Fraim's literature is also described in the paper.
Chemically Enhanced Production – Managing Waxy Condensate
Authors: M Zaini Khairul Nizam , Othman Mohamad , Yunus A. Rahman
Published: December 2007

Waxy condensate was suspected as a contributing factor to the process and operational upsets at one gas-condensate processing platform operated by Petronas Carigali. As an immediate solution, the suspected wells were either shut-in or curtail back, while a detail investigative study is conducted.

The main objectives of the study are to identify the source and quantify the extent of the problem and subsequently formulate appropriate solutions to manage the problem. Key actions implemented include in-situ condensate testing, gas process profiling and extensive laboratory analysis of condensate samples from all producing gas wells in the field. However, the difficulty is to identify the contributing wells due to the nature of the light condensate i.e. high API gravity of condensate, but low pour point as contrast to typical waxy crude where the API gravity is generally low. While wax precipitation from crude has been extensively studied, precipitation from gas condensates is not generally well recognized1.

From the various laboratory analysis data, it was confirmed that paraffinic wax would form at the current operating temperature of the gas-condensate plant. Furthermore, from well analysis data, four wells were confirmed as the potential source of the problem.

Through wax crystal modifiers2 or Pour Point Depressant (PPD) screening and testing using condensate sample from one of the shorlisted well, a suitable chemical was identified for plant testing on two shorlisted wells. A pilot test using the PPD was conducted on-site and the condensate pour point was monitored at both the offshore processing platform and the onshore gas terminal (OGT). Subsequently the performance monitoring data showed that the PPD is able to reduce the pour point of the condensate to an acceptable level. The optimum dosage of PPD treatment was also determined. This encouraging result permitted both wells to produce at their maximum potential.
Experimental Studies on Injecting Wastewater to Improve the Recovery of Abandon Condensate Gas Reservoir
Authors: Ping Guo , Cheng Yuanzhong , Liu Liping , Du Jianfen , Hong Li , Liu Jianyi , Li Shilun , Chang Su
Published: December 2007

It is traditionally considered in China that recovery of condensate gas reservoir cannot be improved by water injection. But, recently work abroad showed that it could be greatly improved by water injection. To address whether the recovery may be improved by water injection, a series of experiments are performed based on the preliminary PVT test. The experiments employed about 1m long-core and compound condensate fluid obtained from Ban 2 Group abandon condensate gas reservoir of DaGang oil field, CNPC. The studies include three main parts: (1) depleting the condensate reservoir to abandon pressure 8Mpa at different velocity to study on the rate effect of recovery. (2) Injecting water into core after pressure reach abandon pressure (3) increasing the pressure to 20MPa by water injection and then keep injection and production balance to study on further condensate and gas recovery. The study showed that condensate recovery measured in PVT cell is half of that tested in long-core, the result is concordant with the practical conditions; exploration by keeping injection and production balance under abandon pressure can further increased condensate recovery by 3.39% and gas recovery by 10.11% and condensate recovery increase with the increase of water injection velocity; balance production under recovered pressure can further increased condensate recovery by 0.68% and natural gas recovery by 5.39%. In-situ test showed that after re-injecting 135×104m3 wastewater into abandon condensate gas reservoir, further 8006t condensate oil and 4885 × 104m3 natural gas were produced to Oct. 2002. The study highlights good economy profits as well as environmental friendly by water injection.
Microbial Prevention of Wax Precipitation in Crude Oil by Biodegradation Mechanism
Authors: Sadeghazad Ayoub , Ghaemi Nasser
Published: December 2007

One of the most severe problems at any oil fields producing paraffinic oils is wax/paraffin deposition. The microbial treatment that based on the activity of the naturally occurring, selectively isolated bacteria is a proved effective alternative method to the conventional methods to prevent and remove wax deposition. This article discusses the screening and evaluation of bacterial strains on the effect of biodegradation on the heavy paraffinic hydrocarbon components (C16+), especially normal alkanes.

The experimental results of cloud point temperature measurements show that as the apparent molecular weight of crude oil (solution) decreases, its cloud point temperature also decreases. So that, wax precipitation will be delayed. Therefore, microbial biodegradation of heavy paraffinic hydrocarbon components, especially normal alkanes, will be one of the most effective methods to prevent wax precipitation and deposition. Three bacteria strains and four different consortia of them were used through the experiments. The three strains were Bacillus subtillis, Bacillus licheniformis, and Pseudomonas aeruginosa.

Gas chromatography, infrared spectroscopy (IR), and NMR analysis were performed on the samples before and after microbial treatments. Also, the physical properties of samples were measured before and after treatments. Based on the physical characteristics of samples and on the results of their special analysis, the Pseudomonas aeruginosa strain was highly effective in the degradation of normal alkanes between C16-C25 and Bacillus licheniformis was highly effective in the degradation of cyclo- and iso-alkanes between C20-C30. In contrast, Bacillus subtillis had no or less effect on the degradation of heavy paraffinic hydrocarbons. Where as, through out the literature, Bacillus subtillis was introduced as one of the effective microorganisms in the biodegradation of heavy paraffinic hydrocarbon components.
Performance Prediction of a Well under Multiphase Flow Conditions
Authors: Marhaendrajana T. , Ariadji T. , Permadi A. K.
Published: December 2007

This paper presents an analytical method to predict production performance of a well producing from a solution gas-drive reservoir. Many available analytical techniques published for a solution gas-drive reservoir have been intended mainly for data analysis techniques and they were proved to be valid only for one particular flow regime (i.e., transient flow).

Many have used Inflow Performance Relationship (IPR) method to predict the well performance in these reservoirs. The shortcoming of this method is that it is based on regression to either field data or numerical simulation results. The data are sampled on one particular flow regime (i.e., boundary-dominated or pseudo-steady state flow). Hence, the outcomes are highly dependent on the condition at which the data are sampled.

The analytical method in this paper addresses all flow regimes (transient, transition, and boundary dominated flow). The solution also considers that all phases (oil, gas, and water) can flow. This solution is also validated with results from numerical simulation for various fluids and reservoir properties.
An Effective Time-Splitting Technique for Full-Tensor Flow Model
Authors: Sutopo Sutopo , Arihara Norio , Yazawa Nintoku
Published: December 2007

A flux-continuous model incorporating full-tensor permeability has been developed for two-phase flow of immiscible and incompressible fluids. Full-tensor permeability is often required to characterize flow from the upscaling process in fine grids heterogeneous reservoirs.

The governing equations can effectively be formulated in fractional flow equations; i.e. in terms of global pressure and saturation equations. An algorithm is implemented applying a highly accurate numerical approach based on the mixed finite volume element (MFVE) method for discretizing the pressure equation, and a combination of the MFVE and the finite volume element (FVE) methods for the saturation equation. The saturation equation is discretized by means of a time-splitting algorithm that allows an explicit time stepping for FVE applied to the advection equation, and an implicit time stepping for MFVE applied to the corrective equation of capillary diffusion.

Numerical experiments of 1-D and 2-D flow are presented to demonstrate the efficiency and robustness of the time-splitting technique. The 1-D Buckley-Leverett displacements verify accuracy and numerical behavior of the proposed scheme. It is also used to determine the optimum time-stepping strategy. The 2-D simulation also show accurate results for full-tensor models and a highly heterogeneous reservoir. It is proved that proposed method can significantly reduce computational time for both 1-D and 2-D displacements.
Effect of Permeability Distribution and Interfacial Tension on Gas Condensate Relative Permeability: An Experimental Study
Authors: Jan Badrul M. , Siagian Ucok W. , Lee Robert L.
Published: December 2007

One of the unique characteristics of gas condensate fluid is the rate dependent relative permeability, also referred to as rate sensitive phenomenon. It has been reported that generated relative permeabilities from gas condensate fluid are sensitive to the flow velocity applied during the experiments. Different flow rate results in different relative permeability. However, this behavior is usually not observed with conventional oil-water or gas-water reservoir fluids and there is no clear answer for the observed rate sensitive phenomenon. This paper will address two of the possible factors that may have caused the dependency of relative permeability on flow rates, namely interfacial tension and permeability distribution. To achieve the mentioned objectives, we measured a series of two-phase relative permeability curves from near critical fluid by means of steady-state technique. A high pressure and high temperature (HPHT) coreflood rig was designed specifically for the purpose of this work. We measured relative permeability at various interfacial tensions and flow velocity. To look at the effect of permeability distribution, we conducted the same steady-state flow tests as in long core, but this time we cut the core to 5.0 in. in length. Results from the study indicate that relative permeability curves seems to straighten out whenever the interfacial tension of the system decreases and flow velocity increases. Experimental results from the short core show significant reduction of the rate sensitive phenomenon in gas and condensate relative permeability. We concluded that the relative permeability of gas condensate is a strong function of interfacial tension. We also found that permeability distribution has significant effect on rate sensitive gas condensate relative permeability. A higher degree of permeability distribution heterogeneity results in larger rate sensitive effect.
4D Seismic in Mapping the Change in Fluid Phase in Carbonate: A Case Study
Authors: Mitra Partha P. , Singh Kharak
Published: December 2007

The ability of 4D seismic to image the fluid flow and locate bypassed oil in between wells especially in carbonate is a real challenge. The seismic observables that change with time as the extraction of hydrocarbon continues may not always be mappable since normally Gassman's equation does not predict the nature of velocity sensitivity to fluid change in most carbonates. However the effect of change in reservoir parameters due to production has a direct impact on seismic signals and is preserved in the form of seismic signature in data volume if they are conditioned and equalized.

The paper presents a 4D study, which was carried out using two 3D seismic surveys acquired over one of the western offshore fields of India. The field produces from Eocene carbonate, which is affected by Karstifiaction. The base survey was carried out in 1989, before the commencement of production. The repeat survey was conducted in 1999, after a time lapse of ten years. The reservoir was developed with peripheral water injection and by 1999 had produced about 16% of initial oil in place. The hydrocarbon column is maximum in the southern part of the field and maximum production had taken place from this sector. The two survey geometries were different and basic processing of two vintages was carried out by two different vendors but more or less same processing sequences were followed. The conditioning and equalization of the datasets were done at post stack stage.

To ensure the repeatability test, non reservoir on both vintages was mapped, surface attribute was computed and difference map was generated. On the other hand, volumetric seismic attribute was computed between reservoir top and initial OWC for base and repeat survey. Difference volume was generated to map the areas affected by water influx and possible areas of bypassed oil. This was later supported by the simulation study.