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The quest for smart and cost-effective demulsification materials to separate water-in-crude oil (W/O) emulsions is highly desired in the petroleum industry. In this paper, an assessment study was conducted on the potency of coal fly ash (CFA) as a demulsifier for W/O emulsions. To our knowledge, this is the first study reporting CFA as a demulsifier for highly stable W/O emulsions. W/O emulsion samples were prepared without using any conventional emulsifier. Asphaltenes in the crude oil acted as an emulsifier and stable emulsions were produced. Six W/O emulsion samples of the same crude oil to water volume ratio (4:6) were formulated. A reference sample was selected for comparison during demulsificat ion. Demulsification tests were performed at room temperature (25 °C). Demulsification results obtained via the bottle tests showed that the reference sample (blank) without CFA remained stable without water separation after 48 hrs while the addition of various CFA quantities (1 % to 7 %) brought about separation of water from the oil phase. Separation of water was observed to have increased with increasing CFA addition in the emulsion. Water separation continued for each sample until around 24 hrs when equilibr ium was attained, and water separation remained constant. The W/O emulsion containing 7 % CFA displayed the highest performance with demulsifica tion efficiency (DE) of 96.67%. Demulsification comparison test results between CFA and a commercial demulsifier (poloxamer - 407) using same concentration and under room temperature showed that CFA was capable of separating water better than this commercia l demulsifier. This observation indicates that CFA can compete favorably with many commercia l demulsifiers available in the market. Additionally, the outcome of demulsification efficiency of 7% CFA at elevated temperatures (i.e., 60 °C and 80 °C) was around 98%. More importantly, the separated water at these elevated temperatures was clearer and contained lesser oil floccules than the separated water phase observed during demulsification tests conducted at room temperature (25 °C) condition. Shear rheology measurement reveals that CFA addition altered the viscoelastic characteristics at the crude oil/water interface at an aging time of 10 hrs and 55 mins. Viscous modulus remained stagnant while elastic modulus dropped significantly. Optical morphology revealed the phase transformation in the as-prepared W/O emulsion before and after the addition of CFA particles. The possible mechanism governing the demulsification of W/O emulsion driven by CFA particles was proposed. It is believed that this work will be relevant to petroleum exploration and refining operations.

The oil mobilization in tertiary mode using chemicals has been shown to be a promising approach. In such technique, surfactants with or without polymers, designed for specific reservoir conditions, are added into water during water flooding to further drive remaining oil out of the porous structure of the reservoir rock into production wells. The success of the method depends on the cost of the chemicals used and the amount of the additional incremental oil mobilization achieved beyond water flooding. Thus, utilizing reservoir-compatible and inexpensive surfactants is a key. Petroleum sulfonates are some of the most abundant and inexpensive surfactants that can be made available at the scale required for efficient oil mobilization operations. However, petroleum sulfonates lack solubility in harsh reservoir conditions which makes them rather inapplicable for reservoirs with high salt content (e.g. > 50,000 ppm) and high temperature (e.g. 100 °C). We have successfully developed a simple, one-step nano-encapsulation technique to transform petroleum sulfonates into nano-sized multi-emulsion droplets in high salinity injection water featuring long-term stability at high temperatures. To further improve the economics and sustainability of such NanoSurfactants (NS), we developed a continuous and cost-effective synthesis process of petroleum sulfonates, directly from crude oil. The in-house-produced sulfonates were then formulated into a NS solution in high salinity injection water utilizing our encapsulation method. Results showed that petroleum sulfonates were successfully synthesized as seen from NMR analysis. The formulated NS was persistently stable at reservoir conditions, altered the wettability of the oil-wet rock as verified by contact angle measurements, and triggered crude oil release from the rock by spontaneous imbibition. This work provides a solution to produce petroleum sulfonates and formulate NS on-site for use in cost-efficient oil mobilization operations in high salinity and high temperature reservoirs.

Excessive water production is one of the major factors in wells’ productivity reduction. It can be resulted from water coning and water channeling from water table to the wells through natural fractures, faults or high permeability zones. The use of foams or gels for controlling water production has been tested successfully in several field cases. However A large treatment volume is required to block the water influx that generally involves high operational and material costs. It is well know that injection of low salinity water into reservoir can mobilize reservoir fines and significantly decrease reservoir permeability. This paper presents the possibility of applying induced formation damage in order to block the water influx without hindering the oil production. This is a new cost-effective method using injection of low salinity water slug. It is shown that system of equations for water injection with induced fines migration and polymer injection is mathematically equivalent. Hence the polymer option in Eclipse-100 is applied to model low salinity water injection with induced fines migration. The modeling results showed that injection of 0.004 PVI of low salinity water above WOC resulted in significant reduction in produced water and improvement of oil recovery with no adverse effect on the oil production.

With the increasing awareness of global warming, geopolymer cement has been identified as one of the methods in reducing the emission of CO2 during oil well cementing operation. However, it is important that geopolymer cement can meet the specific requirement of oil well condition in order to be substitute of current conventional cement system. The use of fly ash in geopolymer based cement can affect the performance of the cement slurry by its properties which yet needs proper study to yield better advantages of it.In this research, the main objective is to study the effect of fly ash in geopolymer cement, by varying the properties which are thickening time, fluid loss and compressive strength. It is identified that the current conventional cement slurry is not environmentally-friendly, and is energy intensive. It is also identified that fly ash produced cannot be recycled and mostly being dumped. Thus, this study can provide the solutions to the problems identified. It involves extensive laboratory work in order to identify the properties of the cement.This project focused on the designation of fly ash based geopolymer cement compositions, the testing of the prepared fly ash based geopolymer with different compositions and different acid concentrations.This report comprises the literature review on the properties of geopolymers, the experimental works and their results, as well as the discussion and recommendations of the project.The tested parameters are water ratio, type and molarity of alkaline activator and alkaline activator ratio.The water ratio is 0.4 with the use of 12M of Sodium Hydroxide and the alkaline activator ratio is 0.4. Sodium silicate and silica fume was added to optimize the compressive strength which proved to have 31% increase of strength. Under low concentration acid, the cement is able to withstand the reaction but failed with higher concentration.The performance of the new blend will be analyzed.

Chemical flooding methods are used to recover residual oil left after water flooding. Several chemical flooding processes have been used to improve recovery. Alkaline-free surfactant polymer combination flooding (SP flooding) can avoid side-effects encountered in alkali-surfactant-polymer (ASP flooding) combination flooding. As part of the ongoing research on the use of Gum Arabic as a polymer in chemical flooding in Nigeria, this paper investigates the effect of heavy oil viscosity on oil recovery during SP flooding. Improved oil recovery through SP flooding was studied by conducting linear displacement experiments using engineering grade class IV glass beads. The glass beads were treated to be strongly water wet. The viscosity of oil samples used for the different experiments ranged from 3 to 140 cp. Lauryl Sulphate and Gum Arabic were used as the surfactant and polymer respectively. Result shows that oil recovery by water flooding ranges from 15% – 25% and for SP 15% – 35% keeping the polymer concentration constant. Thus, increasing oil recovery can be achieved as the viscosities of oil increases. The result from this study will help develop effective methods for implementing SP flooding using Gum Arabic that is vastly available in Nigeria in heavy oil fields. It will give the oil industry a new option for improving oil recovery from heavy oil reservoirs. SP flooding will be handy to improve oil recoveries from many marginal oil fields in Nigeria or those that face shut-down due to uneconomic operating cost, but still contain significant amount of oil.

The formation of emulsion is one of the challenges facing the oil and gas industry today. This is normally encountered when water is dispersed as fine droplets in the bulk of oil. This study presents the treatment techniques used by Nigeria Petroleum Development Company in Oredo field in breaking crude oil emulsion. Wells 2L and 4L were used for the analysis. Crude samples were obtained at the upstream of chemical injection points to ensure the samples were true representatives of the crude from the wells in the field. Chemical demulsifiers (DM1, DM3, DM4, and DM5) were formulated in the laboratory which was used in the treatment of 100ml of emulsion. Results show that DM3 and DM5 were the most effective chemical demulsifiers formulated in the laboratory for Oredo wells 2L and 4L respectively and also, temperature is an indispensable determining factor in the treatment of emulsion.

Foam has been used for controlling gas mobility during injection processes in order to mitigate the adverse effects of low gas viscosity, reservoir heterogeneity and gravity override. In addition, foam has also been employed in near-wellbore production, matrix acidizing stimulation, hydraulic fracturing, gas shut-off and water shut-off. The optimization of these operations requires a good understanding of the physical characteristics of foam and its behavior under reservoir conditions. Despite numerous experimental and theoretical studies on foam and some field applications reported in the literature, there is no comprehensive literature survey detailing the knowledge and experience gained through the application of foam. The aim of this paper is to present a critical review of the literature available on the use of foam injection for enhanced oil recovery. An extensive appraisal of the current status of foam application in EOR methods is a useful way of presenting advantages, shortcomings and limitations of the process as well as supplementary advances. Special attention has been given to the review of new research topics, such as the use of foam as a mobility control agent. Advances in more efficient foaming agents, additives and boosters are discussed. Moreover, in depth analysis of field applications of foam in EOR projects show that the main problems encountered during field-scale foam applications are related to foam stability, foam compatibility, as well as adsorption of the injected chemicals onto the rock surface. To address this, we discuss the evolution of the pilot field application and the reasons for inconsistency between laboratory results and field scale performance.

Water-based drilling fluids consisting of xanthan gum, starch, sized calcium carbonate and salt particles have been used to drill horizontal wells. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, and chelating agents are limited at certain conditions. Drilling fluid was designed based on calcium carbonate particles and an ester of lactic acid. The objective of the latter is to remove calcium carbonate once the drilling operation is complete and there is a need to remove the filter cake. Extensive lab work was done to: 1) determine thermal stability of the drilling fluid (70-72 pcf) for 24 hrs, 2) characterize the filter cake using computer tomography, 3) assess potential formation damage for different rock types (limestone and sandstone) using a modified HPHT filter press, and 4) determine the removal efficiency of the filter cake and the return permeability. The results obtained showed that the drill-in fluid has stable rheological properties up to 250°F over 24 hrs. A CT scan showed that the filter cake contained two layers, one layer close to the rock surface, which contained a mixture of calcium carbonate and acid-precursor, and one layer close to the drilling fluid that contained a mixture of XC-polymer and starch. The polymer layer was removed by using 10% solution of alpha amylase. The rest of the filter cake was removed by lactic acid that was produced from the hydrolysis of the ester. The removal efficiency of the filter cake was nearly 100% and the return permeability was about 100%, when using a ratio of polylactic acid to calcium carbonate 3 to 1. The decrease in the CT number of the core after the removal process indicated that the filter cake was completely removed and no formation damage occurred. This paper will discuss the development of this new drilling fluid and will give recommendations for field applications.

Recent advances in guar and cross-linker technologies have resulted in the development of high viscosity cross-linked borate fracturing fluids without increasing polymer loadings. These Low Polymer borate fracturing fluids (LP) are successfully being utilized in various formations previously believed to be too hot and or too deep for low polymer fracturing fluids. Historically, polymer loadings of 3.6 – 4.2 kg/m3 (30-35 lb/1000gal) were commonly pumped in the Western Canadian Sedimentary Basin (WCSB) for formations deeper than 2500 meters and bottom hole temperatures greater than 80°C. These same formations are now fracture stimulated using the Low Polymer fluids with loadings as low as 1.8 kg/m3 (15 lb/1000gal) with exceptional results. This paper demonstrates that Low Polymer fracture fluids can be used in place of higher polymer fluids with minimal changes to the overall design of the fracture treatment. The new fluid can be pumped on-the-fly at conventional pump rates and proppant concentrations due to the fluid's improved shear and temperature stability. The advantages of using a reduced polymer fracturing fluid include increased production, lower treatment costs, and lower friction pressures. This paper illustrates these advantages as it compares the Low Polymer fracture fluid with High Polymer fracture fluids in over 200 wells in the WCSB. The formations where LP fluids were utilized have depths of up to 3250 meters and reservoir temperatures reaching over 100°C.

Alkyl polyglucosides (APGs) are recognised as sustainable surfactants based on natural raw materials. They exhibit a low ecotoxicity profile and are therefore already used in different oil field applications. In this paper it is shown that APGs have superior solubility properties in high salinity environments. The interfacial tension of crude/brine systems can be significantly lowered even in high salinity brines. The performance of APGs can be improved by optimising the hydrophobic as well as the hydrophilic part of the surfactant. In contrast to standard surfactants used in EOR applications the performance of APGs is not reduced under elevated temperature or high salinity conditions. Their performance is not influenced by typical salinity and temperature gradients as can occur in the reservoir. Moreover, microemulsions can be formed even under high salinity and elevated temperature if APGs are used together with co-solvents.

Horizontal and maximum reservoir contact (MRC) wells are intended to increase productivity and minimize water production due to water conning. Their complex geometry makes cleaning up of drilling fluids filter cake a difficult task. It is hard to distribute the acid uniformly over long horizontal sections. Poor acid distribution occurs during matrix acidizing. Coiled tubing cannot reach the total depth of the well because of some limitations such as large washouts, length of the reel and diameter of the coil, which make acidizing horizontal wells ineffective. Available chemical methods of removing filter cake like mineral acids, esters, oxidizers, chelating agents, and enzymes are limited at certain conditions. This paper introduces a new method for filter cake cleaning using a self-destructing water-based fluid to drill long horizontal and MRC wells, which results in higher productivity. This fluid is a water-based mud that is weighted with calcium carbonate and has both functions of drilling and completion fluids, can reach total depth of MRC wells. It has the ability to effectively stimulate the whole horizontal sections after drilling. This can result in significant cost savings by elimination of acidizing using coiled tubing or any other means and improvement in filter cake removal and thus enhances performance of the treated wells.

The primary objective of acid fracturing is to generate a conductive flow path between wellbore and reservoir. The factors that governed the effectiveness of acid fracturing treatments are etched fracture penetration and its conductivity. The effective fracture length and its conductivity usually depend on (a) acid convection to the rock surface, b) acid reaction rate and (c) acid leak-off into the reservoir. The etched fracture length is limited by the distance traveled by acid along the fracture. This limit is a greater problem especially in high temperature reservoirs, as the reaction rate is very high with conventional acid systems. Excessive fluid leak-off is another factor that limits fracture extension and etched penetration.After treatment, the etched non-smooth fracture surfaces leave open pathways, in addition to the wormholes and channels created from the fracture to the formation. The induced fracture tends to close due the effect of in-situ stresses and decline the conductivity. Factors that contribute to the reduction in fracture conductivity upon completion of an acid fracturing treatment are (a) elastic response, (b) compressive failure of the asperities and (c) creeping effect. Therefore, in most of the cases, the initial response of acid fracturing treatment is highly encouraging. However, the sustenance of production may not be adequate because of either insufficient extension of fracture or closure of fractures under the effect of in-situ stresses. Type of acid and treatment methodologies viz. injection rate, leak-off control measures etc. are having significant impact on success of treatments.To address the issues, different combinations of acid systems were applied in various low producer wells in a tight carbonate reservoir of an offshore field. This paper will present the treatment design, methodology and impact of various acid systems on effectiveness of acid fracturing treatments from field application results.

Oilfield produced water usually comprises both the formation water and injected fluids from prior treatments. Produced water may be environmentally hazardous and usually contains bacteria, hydrocarbons, and high levels of dissolved salts. As such, the proper disposal of produced water is often expensive. Meanwhile, fresh water used to formulate oilfield treatment fluids is becoming more costly and more difficult to obtain. Operators, as well as service companies, have therefore shown a strong desire to use produced water in field operations to reduce costs. Consequently, a series of laboratory experiments have been performed to optimize the viscosity profile of fracturing fluids prepared with produced water. Preparation of polysaccharide-based fracturing fluids with produced water frequently resulted in fluids with poor viscosity profiles despite the fact that the produced water was pretreated with biocide. Furthermore, the problem could not be resolved by just adding more biocide. In a number of representative cases, the guar-based fracturing fluids, prepared with produced water and regular biocide, quickly lost their viscosity after hydration, possibly because of the degradation of the guar by the bacterial enzymes in the produced water. A new fluid stabilizer was recently invented to address the problem, and it was observed that the addition of the stabilizer dramatically extended the lifetime of the polysaccharide-based fracturing fluids prepared with produced water. The fluid stabilizer was simply added to produced water prior to mixing the polymer. The polysaccharide-based fluids prepared with the stabilizer-treated produced water showed stable viscosity profiles at both surface and bottomhole temperatures. The use of the fluid stabilizer has greatly enhanced the fluid performance and job efficiency since its initial introduction in the field in June 2008 and was implemented in about 80 successful fracturing and sand control jobs by the end of 2008. The invention and successful application of the fluid stabilizer have reduced the operating costs for the operators and service companies. At the same time, this new technology has also helped improve the environment by cutting the fresh water usage in the field. This paper will discuss the chemistry, experimental studies, and case histories.

Drag reducing agents are used to reduce significantly the frictional pressure loss under turbulent flow conditions, allowing a substantial increase in pipeline capacity. Their performance is known to depend on their own characteristics (molecular weight, structure, chemical composition) and on external parameters such as turbulence intensity, oil viscosity, etc. The mechanism by which DRAs interfere with turbulence is not fully understood and drag reduction is not easy to predict. Laboratory tests are still required to quantify the potential efficiency of these additives. This paper reports on an original experimental methodology based on the combined use of a classical rheometer and a laboratory loop offering a large range of experimental conditions in terms of temperature, pressure, flow rates and cooling rates. Different commercial oil soluble DRAs have been tested on various fluids including a paraffinic crude oil. The experimental results have shown that either the presence of waxy crystals or emulsified water droplets can alter the DRA efficiency, while they are not affected by waxy deposits or low temperature.

This paper will describe the technical work performed to develop reliable and reproducible testing procedures for standard purified Polyanionic Cellulose Polymers (PAC) and Drilling Grade Xanthan Gum Polymers (XG) leading to the introduction of new specification in API 13 A/ISO 13500. The absence of standard procedures and specifications for PAC and XG materials have created confusing interpretations of the quality and expected performance. This opened the way to adulteration, primarily with starches (in PAC) and guar gum (in XG). A survey made within the API organization identified the need of standard performance testing procedures and specifications for pure-grade PAC and XG materials as well as adopting a test to easily identify the presence of adulterants. Simple procedures have been developed to identify starch or guar gum presence and establish performance testing procedures. Numerous round-robin tests have been performed to fine-tune the testing procedures and measure intra and inter-labs reproducibility. Only testing procedures providing results with an acceptable standard deviation have been approved. A new set of specifications including the following were finally defined: –moisture content, fluid loss and viscosity (for PAC)–moisture content, particle size analysis and viscosity (for XG) The final procedures and specifications for both PAC and XG will be published with the new revision of the API 13 A/ISO 13500 in January 2009.

The growing demand for well-designed weighting agents to overcome the currently drilling challenges such as ECD management and the settling tendency of the weighting agents led to the development of a new micronized ilmenite (FeTiO3). The acid solubility of ilmenite is of great importance to remediate any damage that might occur during its use in the drilling operation.Extensive lab work was conducted to: 1) assess the reaction of 10 wt% HCl with ilmenite particles at 300°F and 300 psi using an aging cell, 2) optimize the concentration of HCl to remove the filter cake using a modified HPHT filter press at 250°F, 3) determine the removal efficiency of the filter cake, and 4) calculate the retained permeability of Indiana limestone cores.The reaction of hydrochloric acid with ilmenite showed that HCl (10 wt%) dissolved 75 wt% of the iron from ilmenite particles after 10 hrs of reaction at 300°F. SEM and XRD results showed that the reaction product was mainly rutile (TiO2) after 6 hrs of reaction.Ilmenite-based filter cake was removed completely after reaction with 5 wt% HCl (300 g solution) for 16 hrs soaking time at 250°F. The retained permeability of the Indiana limestone and Berea sandstone cores was nearly 100% after HCl treatment (5 wt%). Removal of ilmenite water-based filter cake is a simple process as compared with barite water-based filter cake, which cannot be removed using HCl. This study will provide a complete evaluation of the reaction of HCl with ilmenite and will help the drilling and completion engineers to better design the chemical treatments to remove the filter cake for HPHT wells.

Selective plugging by microbial biomass is one of the proposed mechanisms for improving reservoir sweep efficiency in highly fractured reservoirs. In this study, the potential of Bacillus licheniformis strains isolated from oil contaminated soil from the Sultanate of Oman was tested for their ability to grow in induced fractures in carbonate rocks and to divert subsequent injection water to the unswept matrix zones. Three B. licheniformis strains were tested: B17, B29 and W16. Their ability to grow in minimal media with Omani date molasses as the sole carbon source was investigated. Two different concentrations of date molasses (3% & 8% w/v) were tested. It was found that the higher concentration of molasses gave higher growth rate for all strains. The combination of B. licheniformis strain W16 in a minimal medium containing 3% molasses was the optimum condition for maximum cell growth within 18 hours of incubation. Standard Indiana limestone core plugs were used for coreflooding experiments where a fracture was induced by slicing the cores vertically into two sections using a thin blade. The bacterial cells were injected into the cores and the ability of the microbes to grow and plug the fracture was examined. Coreflooding experiments showed promising results where enhancement of oil recovery was observed after bacterial injection. A total of 28.57% of the residual oil was produced after 18 hours of incubation. The results showed the high potential of using date molasses as the carbon source for microbial biomass production for selective plugging in fractured reservoirs.

Formation of emulsions during oil production is a costly problem, both in terms of chemicals used and due to production losses. This paper discusses production and operational problems related to crude oil emulsions, and present a review that will be very useful for practicing engineers. The first part of this paper presents why emulsions form during oil production, the types of emulsions encountered, and new methods for characterizing them. Crude oil emulsions are stabilized by rigid interfacial films that form a "skin" on water droplets and prevent the droplets from coalescing. The stability of these interfacial films, and hence the stability of the emulsions, depends on a number of factors including the heavy polar material in the crude oil (asphaltenes, resins, waxes, etc), solids (clays, scales, corrosion products, etc), temperature, drop size and drop size distribution, pH, oil and brine composition. These effects on emulsion stability are reviewed. The second part of this paper presents ways to tackle crude oil emulsions. The focus is on the destabilization of emulsions and the demulsification process. Emulsions are destabilized by increasing temperature and residence time, removal of solids, and controlling emulsifiers. The mechanisms involved in demulsification (flocculation, aggregation, sedimentation, creaming, and coalescence) are discussed in terms of the stability of the interfacial films. The methods involved in demulsification including thermal, mechanical, electrical, and chemical are also presented. Experience and economics determine which methods and to what degree each method is used for emulsion treatment. Finally, a section on field applications is included that should be useful for the practicing engineer who deals with emulsions, either regularly or on a limited basis. Herein the field emulsion treatment program is discussed, and more importantly, methods to prevent emulsion problems are highlighted. Recommendations are made for reducing and optimizing demulsifier dosage and controlling emulsion problems.

One of the problems that plagues oil companies is the deposition of wax or paraffin inside pipelines. The present invention is a method for mitigating the wax deposition during crude oil flow in a well-bore or pipeline. The method comprises positioning one ultrasonic frequency generating device adjacent to the production tubing walls and producing one ultrasonic frequency thereby disintegrating the wax and inhibiting the wax from attaching to the production tubing walls. Experiments were done to measure the effect of ultrasonic waves at a frequency of 120 kHz on wax deposition during crude oil flow in a pipeline. In this paper, all the experimental results are described. Some reduction in wax deposition was also achieved due to the ultrasonic waves. Further work is required to identify the optimum frequencies.

Supercritical carbon dioxide (SC-CO2) has the characteristics of high density, low viscosity and high diffusivity, and higher penetration rate can be achieved with SC-CO2. But the law of cuttings carrying is not clear, in order to make clear the influence of pump displacement, well incline, cuttings diameter, wellbore temperature and pressure on cuttings carrying efficiency, the laboratory experiments was carried out to simulate the cuttings carrying with SC-CO2 in annulus. The result shows that the cuttings carrying efficiency decreases when pump displacement decreases and cuttings diameter increases, and it decreases with the increasing of well incline at first, and then increases. Wellbore temperature and pressure have much more influence on cuttings carrying efficiency, and it decreases when the wellbore pressure increases, if keeping the wellbore temperature and pump displacement in constant; and it increases when wellbore temperature increases, if keeping the wellbore pressure and pump displacement in constant. So the wellbore temperature can be adjusted to compensate the cuttings carrying efficiency's changes caused by pressure changes, and the excess annulus velocity should be in consideration to avoid erosion of casing, drilling pipe and other down hole tools.

The use of stimulation treatments based on alcohol to remove liquid blockage or condensate banking in the near well zone date from sixties. Among the proposed mechanisms to explain the enhancement in gas effective permeability and also the higher degree of cleaning and liquid removal obtained in laboratory and field studies, are interfacial tension reduction and the miscibility characteristics reached between the treatment fluids and the formation fluids. This paper presents the results for compatibility and displacement tests carried out among reservoir fluids, alcohol and inhibited diesel based treatments and formation cores from main Cupiagua field. These tests are focused about the behavior of these treatments when they are applied in core flooding tests to reduce liquid saturation and also to increase the gas effective saturation in a porous media. The offered results can be interpreted as a preliminary sight about the use of these treatments on lab scale before applying them as stimulation fluids on a field project. The study consists in assess the alcohol-based and inhibited diesel treatments' efficiency through the gas effective permeability before and after of the treatment injection into a core. The objective was focused to study the use of alcohol and inhibited diesel to remove formation damage by liquid blockage and their application in condensate gas reservoirs. The alcohol-based treatments show consistent results about their effectiveness both on core tests carried on Mirador formation, Cupiagua Main Field – Colombia, and Berea sandstone. In general, the results show up an increase on the gas effective permeability, the lower the core permeability the higher the gas effective permeability enhancement reached after the treatment. The alcohol labeled 21-NE-06 and inhibited diesel treatments increase the gas effective permeability both in Berea and Mirador cores. Both Alcohol 21-NE-06 and inhibited diesel based treatments are effective for removing liquid phases that cause a liquid blockage to gas flow. The stimulation degree is higher in Mirador than in Berea cores. Some treatments did not show any stimulation degree, instead, they generate additional gas effective permeability impairment.

Abstract Dispersant application is becoming considerably more utilized as a tool inthe response toolbox at oil spills. The primary application tool in the pasthas been through aircraft. While aircraft application is extremely effective, boat application can be efficiently utilized as an additional tool for deliveryof dispersant. This paper discusses the potential use and awareness for boatapplication of dispersant. Introduction Dispersant use on offshore oil spills has become increasingly more common asa tool to combat the spread of oil spills. Traditionally, here in the United States, oil companies have looked toward aerial application of dispersants. Theuse of aircraft is a valuable tool in the ongoing fight of oil spills andshould never be overlooked. Boat application of dispersants will not replaceaircraft spraying. Boat application should be considered as another toolavailable to qualified individuals (QI), the incident commander (IC), theresponsible party (RP), and the spill management team (SMT) of the oil ortransportation company, or the federal and state government that gets involvedin the task of mitigating the affects of an oil spill. Boat Spray Application of Dispersant Dispersant use in approved locations is not the topic in this paper. Thegovernment has well defined avenues for approving the use of dispersant. Itshould be noted that any use of any chemical in the response to an oil spillmust have complete authorized approval prior to any application. The Oil Pollution Act of 1990 (OPA 90) has had a tremendous impact on oil, transportation, storage and response companies and in the short decade since1989, the United States has seen an unsurpassed effort of the buildup ofresponse equipment, primarily containment, and mechanical recovery equipment. Interestingly enough, the primary dispersant delivery system in the Gulf of Mexico (GOM) was available to QI's, IC's, SMT's, and RP's and was in operationprior to OPA 90.

Microbial Enhanced Oil Recovery (MEOR) is a process where microorganisms are used for tertiary oil recovery. Numerous mechanisms have been proposed in the literature through which microorganisms facilitate the mobilization of residual oil. Herein, we focus on the MEOR mechanisms of interfacial tension reduction (via biosurfactant) and bioclogging in water-wet micromodels, using Shewanella oneidensis (MR-1) that causes bioclogging and Bacillus mojavensis (JF-2) that produces biosurfactant and causes bioclogging. Micromodels were flooded with an assortment of flooding solutions ranging from metabolically active bacteria to nutrient limited bacteria to dead inactive biomass to asses the effectiveness of the proposed MEOR mechanisms of bioclogging and biosurfactant production. Results indicate tertiary flooding of the micromodel system with biomass and biosurfactant was optimal for oil recovery due to the combined effects of bioclogging of the pore-space and IFT reduction. However, metabolic by-products alone were able to recover oil in some cases dependent on wettability. Unaided biomass (i.e. no biosurfactant) that clogged the pore-space also successfully produced additional oil recovery. When analyzing residual oil blob morphology, MEOR resulted in oil blob size and radius of curvature distributions similar to those obtained by an abiotic capillary desaturation test, where flooding rate was increased post secondary recovery. Furthermore, for the capillary number calculated during MEOR flooding with bioclogging and biosurfactant, lower residual oil saturation was measured than for the corresponding capillary number under abiotic conditions. These results suggest that bioclogging is a potentially effective approach for pore morphology modification and thus flow alteration in porous media that can have a significant effect on oil recovery beyond that predicted by capillary number.

Cleanup of filter cake is a difficult task and becomes more challenging when dealing with weighting materials such as manganese tetraoxide. Mn3O4 is a strong oxidizing agent and can be used as a catalyst due to its active phase, which will result in complex interactions with most cleaning fluids. The reaction of selected organic acids and chelating agents with Mn3O4 particles as a function of time and temperature were studied. Atomic absorption was used to measure manganese concentrations and X-ray diffraction to analyze solids remaining after the reaction. White precipitate of manganese citrate was produced following the reaction of citric acid with Mn3O4 up to temperatures of 284°F. The amount of precipitation increased with temperature and initial chelate concentration. GLDA reacted with Mn3O4 particles completely at 190°F. However, a large amount of white precipitation produced. Similarly, a white precipitation was observed with oxalic and tartaric acids. The reaction of DTPA with Mn3O4 particles in glass reactor produced Mn(silicates) at 212 and 284°F. This study will help drilling/completion engineers to avoid using such chemicals to prevent formation damage after filter cake removal treatments.

An amphoteric starch-graft-polyacrylamide (S-g-PAM) was prepared by inverse emulsion polymerization, subsequent hydrolysis reaction and Mannich reaction. The effects of reaction conditions on copolymerization and the use of the polymer as the water clarifier in oilfield water treatment were investigated. The application test showed that the results of oilfield waste water treatment by amphoteric S-g-PAM were better than those treated with cationic polyacrylamide (PAM), hydrolytic PAM and amphoteric PAM.

At some thermodynamic conditions, asphaltenes flocculate into larger, almost spherical particles that have a specific gravity of 1.05 to 1.10. Work is cited here that indicates that asphaltene stable colloids exist in oil as very minute particles and that their pre-flocculation sizes are in the range of about 10 to 15 Å This corresponds to 334 and 1,128 molecular weight respectively, assuming asphaltene spherical colloids and an experimentally determined asphaltene density of 1.06 g/cm3. The reason for this high specific gravity of asphaltene particles compared to the rest of the molecules of oils is that they consist mostly of asphaltenes and resins, the heaviest constituents of oils. Roughly, resins have specific gravities of 0.95 to 1.0 and asphaltenes 1.1 to 1.2. Because of their high specific gravity asphaltene particles settle by the force of gravity in storage systems where the convection currents and shear forces are minimal. Some of these particles are large enough to overcome the convection currents and shear forces and settle in large separators and occasionally in large pipes due to Stoke's law effects, especially at elbows changing the direction of flow where the particles impinge against the pipe wall and are temporarily halted. Wax precipitation often results in the formation of sub-micron wax spherical particles that also settle under the influence of gravity. Although paraffin waxes have specific gravities around 0.8 to 0.85, field waxes have higher specific gravities, usually higher than 0.9, because they usually co-precipitate with asphaltenes and resins, if present. Hence, in oils that contain asphaltenes and resins, precipitating waxes do settle by gravity. It has been shown that asphaltenes and resins are considered responsible for causing the formation of amorphous spherical wax crystal particles rather than wax needle crystals. Both flocculated asphaltene particles and crystallized wax particles agglomerate to form very large micron-level particles whose molecular weights run in the hundreds of thousands or millions. These large particles settle fairly quickly in storage systems. This paper presents a modeling methodology for the simulation of sedimentation of asphaltene and wax particles in both onshore and offshore storage systems. The asphaltene and wax particle size distribution is usually available from microscopic observations, filtration, and thermodynamic models. The sedimentation calculation is done by assuming that the particles have settled and are at gravimetric equilibrium. Two examples are presented: one 1,000,000-barrel FPSO case and one 250,000-barrel oil storage tank case. Both the FPSO and the tank had lost a substantial fraction of their capacity due to accumulation of asphaltene and wax sludge.

This paper presents a case history on new sandstone acidizing technology using a nonhydrofluoric formulation to successfully treat a high carbonaceous sandstone formation. The improved understanding of the chemical complications of hydrofluoric (HF) on dirty sandstones led to the design of a nonhydrofluoric treatment on the high carbonate content (dirty) sandstone formation. Previous treatments using various formulations of HF acid failed to remove the high skin associated with several wells in this formation. A new approach was taken to identify the damage mechanism and evaluate damage removal options based on the formation mineralogy. This approach analyzed the potential chemistry risks associated with using HF type treatments in the presence of particular mineralogies and temperatures. The new approach also used logging and reservoir modeling technology to forecast the estimated production profile of the complex multilayered formation. Candidate wells were identified by comparing the forecast production profile potentials to the surveyed production profiles based on production logging (PLT) of the prescreening candidates. The final treatment candidate was then selected for the trial of the new treatment formulation. The treatment was specifically tailored based on the identified mineralogy and encompassed the damage prevention strategies. The result was a 40% increase in oil production for the well, but a 2-fold to 10-fold increase for the treated zone, depending on pretreatment production assumptions.

Abstract This paper presents the results of laboratory treatment works on upgrading the bentonite from two areas of Sabah, Malaysia, namely Andrassy and Mansuli for the uses in petroleum industry. Bentonite, as a common material used in water based drilling mud is the sodium bentonite. Since the Malaysian bentonite is proved to be calcium based, certain treatment is needed to convert this bentonite to sodium variety. The successfully treated bentonite will be used as a material in drilling mud, which is cheaper as compared to the Wyoming and standard bentonite. This study included two treatment processes; wet treatment and electrolysis. Several sodium sources have been studied but only the sodium carbonate can successfully be used to upgrade the bentonite. The results obtained after these two treatment processes showed improvement in cation exchange capacity (CEC), which is about 27% increment for electrolysis treatment and 22% to 29% for wet treatment, respectively. However, the treated bentonite failed to meet the API 13A Specification (American Petroleum Institute) requirements for rheological properties when used as a material in drilling mud. Thereafter, certain polymer extender had been added to improve rheological of the upgraded bentonite slurry so that it can be used as a drilling mud material. In general the treated bentonite from Malaysia can be used as a replacement for the more expensive imported bentonite especially for local petroleum industry. In addition, the methods developed can also be used to convert the similar type of bentonite from other locations, since the large deposits of calcium based bentonite can be found in Malaysia. Introduction In order to reduce the overall cost of bentonite used in local oil and gas industry, the feasibility study of Mansuli and Andrassy bentonite application had been initiated. Before these bentonite can be used, their physical and chemical properties and their performance as compared with the standard bentonite must be determined. If their performances are not as good of standard bentonite, treatment ought to be applied to convert the counter ion that placed between the unit clay surfaces. The type of counter ions has a great effect on the swelling capacity of the montmorillonite mineral and by far the best performance is obtained with sodium-based montmorillonite mineral, which has sodium as counter ions. If the montmorillonite mineral in bentonite contains counter ions other than sodium, the swelling properties, viscosity build-up and filter cake permeability will be adversely affected. Three sources of samples that were used in this study, two sources namely SA5–1 and SA5–4 from Andrassy of Tawau area and the other namely M4 from Mansuli of Lahad Datu in Sabah. These bentonite are proved to be non-sodium based, which are different from the commercial sodium based bentonite according to chemical composition, chemical and physical properties such as Atterberg limits, moisture content, moisture adsorption, ignition loss, specific surface and cation exchange capacity. Experimental Works Bentonite Sample Preparation Bentonite samples from the field will be dried in the oven at 55 °C for four hours until moisture content become less than 10%. Then the sample will be crushed using grinding machine till it become powder. Selection of bentonite grain size is very important to obtain optimum cation exchange. API Specification 13A showed that the needed particles size to be used should less than 74 (m, which can be achieved by using wire cloth sieve. Mineral Composition X-Ray Diffraction (XRD) analysis had been used for mineralogy determination and the test was done by using Siemens D-5000 fully automatic diffractometer. The mineralogical constituents within the bentonite sample can be directly characterized giving critical information as to the geological evolution of rock samples.

Heavy oils are becoming increasingly attractive from the standpoint of availability of reserves and economic status as "opportunity" feedstocks. However, they also bring some complex dehydration problems including high levels of suspended solids, conductive organic species, and varying amounts of semisoluble and precipitated organic materials. Meeting these challenges requires new techniques in both the areas of chemical treatment and dehydrator design. This paper focuses upon improvements in hardware design.

Sugar is widely recognized as a cement retarder by the drilling industry and has been used in cementing operations where cement returns are expected on surface. Experts disagree about the effect that sugar has on cement slurries, a few believe that it acts as both an accelerator and a retarder depending on the concentration, but the majority believe that the sugar acts as a retarder only. Lab tests of thickening time and compressive strength were conducted using different concentrations of sugar. The results indicated that the sugar acts as a retarder of cement slurries when added in small concentrations and as an accelerator when added in high concentration. The compressive strength tests showed that the accelerated slurries developed very little or no compressive strength, indicating that no hydration of the cement grains occurred. The retarding mechanism of the sugar is well documented, but the acceleration effect is not widely known. An attempt was made to explain the mechanisms involved in the shorter thickening time and lack of compressive strength observed at high sugar concentrations. These project findings are of great practical importance to the drilling industry. Sugar is currently used in the field with the idea that it will always retard the slurry.

Abstract As watercuts increase, tight emulsions formed in the produced fluids from some wells in Saudi Arabian oilfields are causing problems at an increasing number of wet crude handling facilities. The processing of these fluids impacts operations in three major areas:–Inability to produce some wells, particularly during cooler weather.–Plant upsets due to grid trips and accumulation of sludge in vessels.–Increased chemical demulsifier demands. The overall effect is an increase in treatment costs and loss of revenue. In January 1995 a multi-disciplined emulsion study team was formed. As part of this study the Laboratory implemented the following stepwise investigation strategy:Develop an Index to compare emulsions for tightness.Perform tests for the physical and chemical characterization of the emulsions.Develop a model to correlate emulsion tightness with analytical data.Based on the above findings make recommendations for improved emulsion treatment. The paper discusses the development of an Emulsion Separation Index (ESI) through investigation of the effect of mechanical chokes on emulsion stability. Details of other tests - including droplet size, viscosity, TGA, organic and inorganic solids content, composition and particle size distribution are reported and related to emulsion stability. The emulsion formation mechanism developed from the above data is described. A model of organic and inorganic solids precipitation caused by shear and pressure drops during production is developed with reference to the literature. The paper concludes by using the model to make recommendations for solutions to the problems and for field trials and further laboratory work. Introduction Crude Production. Saudi Aramco is responsible for maintaining oil production throughout Saudi Arabia. Oil produced varies from Arab Heavy (API 27) through to Arab Super Light (API 51). This paper deals with emulsions encountered during the production of Arab Light (AL - API 31–33) The wet crude is processed through Wet Crude Handling Facilities (WCHF's) where demulsifier chemicals are added at the Production Header. The Company produces AL through around 20 WCHF's of up to 330MBD capacity. Since there are no fired heaters, problems with tight emulsions are typically encountered during the cooler months when demulsifier requirements increase from Compared to many parts of the world, peak demulsifier demands of 20ppm may seem to be a minor inconvenience. However, in view of the millions of barrels of AL produced, the potential for savings by reducing chemical use is considerable. Impact of Emulsion Problems. As the oilfields mature and watercuts become higher, oil/water emulsions are causing operational problems at an increasing number of (WCHFs). Processing of tight emulsions impacts operations in the following areas:–Inability to produce some wells, particularly in cooler weather. This results not only in loss of revenue, but also has a negative impact on long term Reservoir Management. - Upsets in WCHFs due to grid trips in vessels.–Accumulation of sludge in vessels, increasing downtime and decreasing residence times.–Increased demulsifier usage (and hence chemical costs) by a factor of five to ten times. The overall effect is a significant increase in treatment costs and loss of revenue. P. 675^

Ivanhoe Energy's proprietary heavy oil to light oil (HTL) upgrading technology is designed to cost effectively process heavy oil in the field and provide a stable, significantly upgraded synthetic oil product along with by-product energy which can be used to generate steam or electricity. Analysis shows that HTL can virtually eliminate cost exposure to natural gas and diluent and capture the majority of the heavy to light price differential for oil producers. HTL accomplishes this at a much smaller scale and at reduced per barrel capital costs compared with established competing technologies. The HTL petroleum processing represents the application of a commercially proven technology to a new feedstock. Ensyn Group, Inc. initially developed the technology in the early 1980s and has applied it commercially for over 15 years in the biomass (wood) industry. Seven commercial Ensyn biomass processing facilities are in operation in the United States and Canada, with a major expansion recently completed in Canada. Ensyn initiated petroleum processing in 1997. A petroleum pilot plant built in 1998 has been used for testing crude oil from around the world. In December, 2004, Ensyn initiated operations at a 1,000-barrel-per-day commercial demonstration plant in the San Joaquin Valley in southern California. Ivanhoe and Ensyn merged on April 15, 2005, and Ivanhoe gained full ownership of the petroleum upgrading technology for the development of heavy oil reserves around the world. Ensyn Group spun off its existing biomass processing business, Ensyn Renewables Inc., to its shareholders prior to the closing of this transaction. Since the commissioning of its commercial demonstration facility (CDF) for upgrading heavy oil in early 2005, Ivanhoe Energy has tested a number of crude oils and vacuum tower bottoms feedstocks. Analysis of CDF performance shows that the HTL process is capable of delivering high yields of significantly upgraded product. The HTL process significantly reduces or eliminates most contaminants and the product typically meets pipeline specifications without further treatment. CDF run analysis validates data obtained in over 90 pilot scale experiments. Results of CDF runs, including plant performance data, CDF feedstock and synthetic product properties are presented.

Summary Production of hydrocarbons is usually accompanied by the production of water. This produced water consists of formation water and/or water that has previously been injected into the formation. As more oil is produced, the amount of produced water increases. Unfortunately, the produced water is not a saleable product; hence an operator must find ways to handle relatively large amounts of water in an environmentally-acceptable manner at the lowest cost. One way of managing this water is to re-inject it for disposal, pressure maintenance, or enhanced oil recovery. An important and difficult task in the re-injection process is the prediction of the impact of water quality on well injectivity. This is mainly because of the poor understanding of the deposition mechanisms by which suspended solids and oil droplets present in the produced water are retained by the formation. As part of a study on formation damage, different concentrations of hematite particles suspended in water were injected into sandstone core samples at residual oil saturation. The theories of deep-bed filtration are evaluated. The effects of residual oil on the filtration coefficient λ and the formation damage factor β are examined. The presence of oil caused greater apparent damage (reduction of permeability). It was also observed that there is rather deeper invasion at residual oil saturation than at full brine saturation.

Filter cake removal is a difficult task, especially in horizontal and extended reach wells. Water-based drilling fluids consist of xanthan gum as a viscosifier, starch as a fluid-loss control, sized calcium carbonate or salt particles to increase the mud density. Conventional chemical means used to remove filter cake are reactive mineral acids, enzymes, chelating agents, oxidizers, or combinations of these chemicals. Controlling of the reaction rate of the cleaning fluids with the filter cake material is an essential factor that determines the efficiency of filter cake removal. This study assesses the performance of three acid precursors (esters) that produce organic acids. These precursors produce low-molecular weight organic acids that can dissolve calcium carbonate particles from the filter cake. The rate of hydrolysis of acid precursors can be adjusted to produce a predetermine acid concentration at bottom hole conditions. Enzymes, mainly α-amylase, can be added to these esters to break starch that is present in the filter cake. The slow release of these weak organic acids ensures proper and efficient removal of the filter cake. Lab studies using static HPHT filter press indicated that the three systems can remove the filter cake efficiently. The rate of hydrolysis was measured for each system, and found to be a function of temperature and type and concentration of the acid precursor. Surface tension measurements conducted for solutions of the three precursors at different temperatures highlighted low surface tension values for the spent acids, which are needed to lift the spent acid following the treatment. No phase separation or precipitation was observed when the three systems were heated at temperatures up to 250°F. Surface tension measurements indicated that the formic acid system had low surface tension, which will accelerate lifting these fluids from tight formations. Acetic and lactic acid systems had much higher surface tension, and a suitable surfactant will be needed to reduce the surface tension. The kinetic study indicated the very rapid reaction rate of the precursor of formic acid and a moderate reaction rate in the acetic acid system. The reaction rate of the precursor of lactic acid was in between the two systems and more close to the in-situ acetic acid system. HPHT experiments showed that formic acid system was very efficient at short soaking times at temperatures of 200 and 250°F. The performance of lactic acid was comparable to formic acid when the soaking time was increased from 4 to 6.75 hrs. The efficiency of acetic acid was much lower than the other two acids. Acetic acid will require much longer soaking times.

Abstract The paper discusses experimental and theoretical studies on the effects of disproportionate permeability reduction (DPR), i.e., the ability to reduce relative permeability to water more than to oil. The theoretical part discusses DPR effects by simple analytical arguments, supported by simulations. DPR causes build-up of water saturation in the treated zone to accommodate the water/oil ratio delivered by the reservoir. Core flooding experiments were also carried out, with a DPR gel placed in one half of the core. There is excellent agreement between theory and core flooding results. It was observed that the water saturation in the treated zone increased. Saturation profiles were measured using a CT scanner and is well matched by simulation. Introduction Increasing water production is a growing concern for the maturing North Sea fields. The need for near-wellbore treatments, with the aim to reduce excess water production without sacrificing oil production, has focused on the use of polymer gel systems reported to reduce the permeability to water much more than the permeability to oil. Particularly in wells where water and oil is being produced from the same zone so that the water bearing zones cannot easily be isolated. Homogeneous reservoir formations with significant oil and water production, or reservoirs with significant crossflow between layers are strong candidates for simpler placement procedures i.e., non selective or bullheading, that will lead to significant savings in time and cost for the well treatment. Polymer and gel have been reported to reduce the relative permeability to water more than the relative permeability to oil. Similarly, foam in porous media is known to reduce relative permeability to gas much more than to water or oil. Such chemicals are referred to as disproportionate permeability reducers or relative permeability modifiers. The literature claims that since the permeability to oil is little influenced, water from watered out zones is held back and thereby the oil production may increase. The paper discusses the effects of placing such chemicals in the immediate vicinity of a production well. Our concern is the effect of DPR treatments on fluid flow patterns in the reservoir and not the mechanisms actually bringing about DPR. The aim of this paper, is through simple theoretical considerations supported by core flooding experiment and simulations, to understand when, and why, DPR treatment may, or may not reduce excessive water or gas production. The reasons why some polymers and gels gives DPR are not yet fully understood. In the literature polymer adsorption, gel syneresis and swelling and segregated pathways for oil and water are among the suggested mechanisms. Here, the details of DPR are not important. The essential is the disproportionate reduction of water or gas mobility, by whatever mechanism. Saturation build-up in treated zone Consider single layer oil production by water (or gas) flooding, see Fig. 1. Gravity and capillarity are neglected. Capillary effects are less important the larger the spatial scale under consideration, and known to be negligible on the reservoir scale. Even in the well region, such effects are generally unimportant due to the dominance of viscous forces caused by the high flow velocities. Gravity effects, on the other hand, may sometimes be quite important in coning-type situations, as discussed later. Basic mechanisms, one dimension. The remaining oil saturation at breakthrough of water may be quite large, depending on fluid/rock properties. P. 483^

New size-controlled microgels formed by crosslinking polymers under shear flow are very promizing for various applications in oil production. Indeed, when produced by using a proper polymer/crosslinker system and under the conditions needed to obtain the desired properties, these microgels should be quasi-ideal products. They are expected to control water mobility at long distances from the wells to improve sweep efficiency and reduce selectively permeability to water for water production control. For this latter application, injecting stable, preformed microgels eliminates the risks inherent to in-situ gelling which is a technique now recognized as being very difficult to control. This paper reports the results of new lab experiments conducted to complete our theoretical description of the crosslinking-under-shear process and to test the properties of these microgels in porous media. The actual properties of these microgels are compared to theoretical predictions. The results provide new theoretical insights into microgel formation and show that such microgels 1) have sizes measured directly by Photon Correlation Spectroscopy which are satisfactorily predicted by our model 2) adsorb quasi-irreversibly, forming adsorbed layers having a thickness equal to two times their viscometric radius of gyration, thus, are capable of controlling permeability more efficiently than the polymer alone 3) can be injected in porous media without any plugging tendency 4) have small internal rigidity as suggested by elastic modulus measurements and thus, they should be ideal disproportionate permeability modifiers 5) have viscosity higher than polymers in the dilute regime and extremely high in the semi-dilute regime, and 6) are stable, showing no tendency to re-form larger microgels when ageing, in presence of a suitable stabilizer.

SPE Member Abstract Beyond the ongoing major structural changes and cost savings resulting from the industry focus on increasing operational efficiencies, better technology holds the key to future reductions in the production cost of oil and gas. Achieving optimum productivity is a major component of this technology. In the past most of the technical and operational aspects of production enhancement were keyed towards making reservoirs economically viable. This limited the application of such operations mostly to low permeability reservoirs, or when there was a drastic reduction in production rates. With the real price of oil steadily declining this need is continually extending towards higher permeabilities. With focus on getting best return on investment it is no more enough to just be profitable. Optimum well productivity will enhance the economic value of any reservoir!! This paper will examine the economic impact of damage removal and production enhancement on reservoirs generally viewed to be high permeability. Introduction Results of stimulation treatments are usually calculated in terms of the ratio of production after fracturing to that before. This technical approach shows that as the formation permeability increases it becomes more and more difficult to create a fracture with sufficient permeability to yield high folds of production increase. Furthermore, theoretically, stimulating high permeability reservoirs does not change the total production by a significant amount. As a result some operators have been reluctant to stimulate high permeability formations. Another cause for this reluctance has been the absence of a financial need to stimulate a high permeability well which is already producing at a profitable level. Some operators have viewed such action as being risky. The approach of this paper is to view stimulation results in terms of their financial value and the associated cost/return possibilities. This approach is chosen based on the economic realities of the oil industry; the need for universal optimization of the efficiency of all operations. The obvious options for reducing cost per barrel of produced oil are either to reduce the cost of operations, and/or, increase the production; the latter of which is the focus of this paper.

Water is usually considered insoluble in the oil phase, however, at the typical temperatures encountered in steam injection process, water may have higher than 40 mole% solubility in the oil phase. We developed a practical and robust algorithm for water/oil/gas three-phase flash calculation. The algorithm is based on the well-developed vapor-liquid two-phase flash calculation algorithm and avoids trivial or false solutions commonly occurred in multiphase flash calculations. We also developed a fully compositional, thermal reservoir simulator, considering water/oil mutual solubility, to study the effect of water-in-oil solubility on oil recovery in steam injection process. Simulation study shows that when water is soluble in the oil phase, it may appreciably increase oil recovery. We also found that the oil fluids should be characterized with at least 3 components for accurate compositional thermal reservoir simulation study.

Despite their already widespread and successful use in several industrial branches, zirconium compounds are underexploited in the drilling industry and have a great potential for more applications1. An innovative product based on zirconium citrate can control high temperature gelation of bentonite at temperature exceeding 400°F or increase the temperature stability of all kinds of lignites and lignosulfonates in dispersed muds. In polymer muds the use of this compound can strongly reduce the need for mud dilution by controlling unwanted increases in mud viscosity and is an effective means for stabilizing rheology during stopped circulation. This biodegradable and non toxic product looks promising as a replacement for potassium dichromate and Cr-lignosulfonates in high temperature applications. Laboratory studies and field experiences are described in this paper, together with ecotoxicity data.

The purpose of the study is to develop a compact electrocoalescer. To improve oil/water separation, definition of optimized conditions for coalescence of water droplets under an electrical field in combination with optimal hydrodynamic performances was performed. Numerical simulations carried out with the CFD code fluent permit to design a new dehydrator integrating the three functions of electrocoalescence, centrifugation and phase separation. A first part consists of two concentric cylindrical vessels used as electrodes with a tangential flow introduction. Then the speed of water droplets is accelerated in a second step by centrifugal effect. Finally, the water flow is separated from the oil phase in a third part. A laboratory prototype was built and tested in various conditions of flow rate and with different types of crude oil/water emulsions. Encouraging results led to define and patent a new concept of compact centrifugal electrocoalescer.

In Brazil, some substances are not allowed to be added to commercialised fuel, because their use would imply tax evasion, since these substances are not taxed. Therefore, monitoring the quality of commercialised fuel is a very important issue. This work presents and discusses the influence of the addition of different proportions of n-paraffin, mainly n-hexane, kerosene and diesel oil on the distillation profile and octane number of automotive gasoline. The results show that it is possible to add non-allowed substances while keeping the automotive gasoline within specification limits. This means that much research should be undertaken in order to establish methodologies that can allow inference of the presence of such substances through physicochemical analyses, even at low concentrations.

Liquid holdup may decrease the productivity of gas producing wells. The use of foaming agents is a popular method of reducing fluid levels and increasing well production. However, corrosion rates may still be excessive in these cases requiring a mitigation strategy. The use of chemicals that act as foaming agents and corrosion inhibitors have great utility in gas wells with excessive water holdup. The underlying physical principles and measurable parameters include dynamic interfacial tension, foaming ability, and corrosion inhibition. A mechanistic description to predict the performance of chemical foamers is developed based upon measurable parameters demonstrating that the dominant factor is foam density. In addition, the effectiveness of a chemical program to unload a well and inhibit corrosion is demonstrated.

An extra-heavy crude oil underground upgrading process is described which involves the downhole addition of a hydrogen donor additive (tetralin) under steam injection conditions. Using a batch laboratory reactor or a continuous bench scale plant (280-315°C and residence times between 24-64 h), physical simulation experiments showed an increase of at least 3° in API gravity of the treated Extra-Heavy Crude Oil, three-fold viscosity reduction and, approximately, 8% decrease in the asphaltene content with respect to the original crude. It was found that the presence of the natural formation (catalyst) and methane (natural gas) is necessary to enhance the properties of the upgraded crude oil. Compositional-thermal numerical simulations were carried out and the results showed a good match between the calculated and experimental °API gravities of the upgraded crude oil (average relative error 1-4%) for all conditions studied. Similar results were obtained with the asphaltene contents (14-23%), percentage of conversion of the >500°C fraction (12%) and tetralin (16-23%).

Abstract The determination of yield points in cement slurries is important in the overall description of slurry flow properties. Yield points-affect both the start-up pressure properties. Yield points-affect both the start-up pressure after a temporary shut-down and void filling properties of cements. Values for the yield point are normally obtained by extrapolation of rotational or tube flow rheometer data. This technique is subject to both experimental and analytical errors. Recently, a number of papers have described a more direct method of measuring yield points in slurries. A rotational viscometer equipped with a vane rather than a bob can be used to accurately measure yield points. The yield surface with the vane test fixture is in the fluid rather than at a fluid-solid interface as it is with a solid bob or a tube flow apparatus. Experiments with a vane fixture using a shear rate controlled rheometer can be subject to errors caused by wind-up of the torque spring. In this study a controlled stress rheometer was used to circumvent these problems. Yield points for various oilfield cement slurries are presented. Data reflect the differences in additives, aging presented. Data reflect the differences in additives, aging time and water content. The vane technique can be used to produce accurate and reproducible measurements of yield points in cements. Using a controlled stress instrument has a number of advantages in making these measurements. Introduction Yield stress (tau y) of a fluid is defined as the minimum stress required to deform the fluid. In this paper tau y will also be referred to as the Bingham yield stress. Below the yield stress the fluid acts as an elastic solid and above the yield stress the fluid flows with a plastic viscosity (mu p). This is a statement of the von Mises criterion for fluids with a yield point. The equation (Bingham equation) which governs the flow of a fluid with a yield stress is given by (1) where tau is the shear stress and gamma is the shear rate. Unfortunately, for fluids equation 1 is an idealization of the actual flow. In controlled shear rate experiments the stress normally builds exponentially at small shear rates to yield data which is similar to the data points shown in Figure 1. Papanastasiou presents a constitutive equation (2) which accurately describes the behavior of a real system over a wide range of shear rates. (2) Where mu is the viscosity of the fluid after yielding, D is the rate of strain tensor, tau is the stress tensor, and pi D is the second invariant of the rate of strain tensor. This rather imposing equation can be reduced to (3) for viscometric, one dimensional flows. Equation 3 is similar to the Herschell-Bulkley equation with a term (1 - e-m gamma) that modifies the yield stress parameter. P. 167

Deliquescing desiccants have been used for gas dehydration for over 40 years. Historically this technology had limited applications due to poor desiccant quality and integrity, equipment design problems, operational difficulty, and limited drying ability. Recent advances in dry material blending and tableting, formulation, and equipment design have greatly expanded the application range of deliquescing desiccants. Deliquescing desiccants are now used to dry sales gas, fuel gas, sour gas, excess or "peak" gas, and for hydrate control. Operating and capital costs compare favorably to traditional TEG systems. Field data verifies the drying ability and performance of deliquescing desiccant systems. Because of the operational simplicity and closed system design, deliquescing desiccants offer many advantages over traditional drying methods such as triethylene glycol, including: no VOC or BTEX emissions, no ground contamination, no fire hazard, low capital expense, low maintenance, no "turn down" concerns, and simple operation. Used for hydrate control in gathering systems, desiccants offer a simple and inexpensive method to dry below pipeline dewpoint thereby allowing trouble free gas flow from wellhead to processing plant. At the plant, gas is further dehydrated to meet pipeline requirements. Desiccants have substantial advantages for drying sour gas both for hydrate control and pipeline sales. There are no emissions, odors, or glycol contamination, and vessels can be over-sized to extend the service interval to only several times per year, greatly reducing employee exposure to hydrogen sulfide. Because of it's simplicity and small footprint, desiccant drying of fuel gas yields increased revenues by using suction gas, not sales gas, for compressor fuel. The entire compressor throughput capacity can be sold, instead of a portion being used for fuel. Desiccant dehydration is well suited for remote, unmanned locations, which are not visited daily. Because operation is simple and service intervals long, operators can schedule maintenance and service weekly or even monthly. This reduces total operating costs and labor requirements.

SPE Members Abstract Glycol dehydration units utilized in natural gas service have been identified as potential sources of aromatic hydrocarbon emissions into the atmosphere. Depending upon the concentration of aromatic content in the natural gas, large amounts of aromatics may be concentrated in the still overhead water vapor vent. Federal and state regulations have targeted glycol dehydration units for emission control on these carcinogenic compounds. In the near future, some states will levy annual fees to operators who exceed maximum daily discharge limits. Conoco has developed and applied for a patent on a novel addition to the standard glycol dehydration unit that eliminates the emission of almost all of the aromatics and other hydrocarbons. Hydrocarbons, that are normally vented with the water vapor, are recovered as a condensate product or as regenerator fuel. A prototype of the Aromatic Recovery Unit (ARU) was successfully placed in operation in November 1990, along with a new 30 MMSCFD glycol dehydration unit. Two additional units are now built and in operation. This paper describes the design and Conoco's experience with the prototype Aromatic Recovery Unit. Background Most natural gas sale contracts limit water content of the gas to 7.0 pounds or less per million standard cubic feet of gas (1 MMSCF). To achieve these low water contents, producers use various means of dehydrating the gas. Among the most popular is the use of Triethylene Glycol (TEG) as the desiccant. By contacting the gas with TEG, water vapor is absorbed and removed, yielding dehydrated gas for pipeline sale. TEG, in addition to having good water absorption characteristics, has a high affinity for aromatic hydrocarbons. When dehydrating natural gas containing aromatic compounds, TEG will readily absorb the aromatics along with the water vapor. This phenomenon tends to concentrate the aromatic compounds in the "rich" glycol stream. The "lean" TEG is regenerated with heat by vaporizing the water and hydrocarbons out of the "rich" TEG. In a standard glycol dehydration unit (GDU), the still overhead vapors are vented to the atmosphere. The vented stream, which is primarily water, contains varying amounts of hydrocarbons. These contaminants include free gas passing through the system and small amounts of heavier paraffinic and aromatic hydrocarbons. In many systems, some of the vapors are condensed in the still vent line through natural cooling. The condensate that reaches the ground contributes toward contamination of the soil and groundwater. The main aromatic hydrocarbons found in natural gas are the B-T-E-X components. Component Chemical Formula Benzene C H Toluene C H Ethyl Benzene C H Xylenes C H P. 655^

SPE Member Abstract This paper describes laboratory investigation of alternate solvent systems and their application to the removal of organic deposits. Aromatic solvents, such as toluene and xylene, have been popular remedies for near-wellbore cleanup operations. Stricter regulations governing disposal, volatile-emission limits, and flammability/handling concerns have made the use of toluene and xylene less attractive. In an effort to limit environmental and personal exposure hazards, alternate solvents have been investigated. Theoretical solvency parameter comparisons linked with a data base search was used to initially screen alternate solvent systems. Quantitative paraffin and pipe-dope solvency tests, along with asphaltene stability titrations, were used to qualify potential solvent candidates. As a result of this work, several potential solvent candidates. As a result of this work, several alternative solvents have been found which fall outside the regulatory restrictions for xylene and toluene, while maintaining effective removal of paraffin, asphaltene and pipe-dope deposits. Introduction Changes in temperature, pressure drop, pH, C:H ratio, and gas/fluid ratio during crude oil production can cause paraffin and asphaltenes to deposit in the formation, wellbore tubing, surface flowlines, and storage tanks. Organic formation damage causes two negative consequences with conventional acid treatments:The damage is bypassed due to immiscibility with the acid system.The water zone is preferentially acidized. Solvent soaks and continuous solvent preferentially acidized. Solvent soaks and continuous solvent treatments are popular methods for removing acid-insoluble formation damage prior to acidizing, oil-external emulsion blocks, and residual pipe dope prior to perforating and gravel packing. packing. Aromatic solvents, such as toluene and xylene, have been popular remedies for near-wellbore cleanup operations. Stricter popular remedies for near-wellbore cleanup operations. Stricter regulations governing disposal, volatile emission limits, and flammability/handling concerns have made the use of toluene and xylene less attractive. In an effort to limit environmental and personal exposure hazards, alternate solvents have been investigated. Background Solvents Most operators consider toluene and xylene to be the best solvents for organic deposit removal. A number of other solvents and formulations have also been used, including aromatic distillates, Stoddard solvent (a petroleum naptha mixture commonly used for dry cleaning), natural extracts, hydrolyzable aprotic halogenated organic solvents such as allyl chloride, and water-soluble thiocarbamates, thiocarbonates and xanthates which settle to the bottom of a well and decompose into CS. Aromatic solvents have been combined with alkylaryl sulfonic acids for asphaltene removal. Aliphatic or cyclic amines have been shown to enhance asphaltene solubility. Cosolvents are often used in many solvent formulations for water wettability but are generally viewed as enhancements to solvent compatibility and penetration rather than enhancement of organic solvency. Higher temperatures enhance paraffin solvency for most solvents but have no effect on asphaltene solvency. Environmental Concerns Although toluene and xylene are considered to be two of the best solvents for organic deposit removal, their use is sometimes restricted due to environmental concerns and stricter governmental regulations. Concerns over the concentrations of benzene, ethyl benzene, toluene and xylene (BETX) in aromatic solvents have been related to a perceived need to steer away from an EPA "hit list" of toxic chemicals. P. 447

Foamed oil emulsions can exhibit significant increases in apparent viscosity due to the entrainment of gas bubbles in the oil. Crude asphaltic components act as natural foaming and emulsifying agents. Their influence causes a large portion of the dissolved gas, which would otherwise be liberated as free gas, to remain entrapped in the water-in-oil emulsion as small bubbles. Such in-situ generation of foamy oil emulsions in the vicinity of the wellbore can have a profound effect on well productivity. This type of formation damage has been found to be fairly common in low gravity oil reservoirs where steamflooding or steam stimulation is used to enhance oil recovery. A novel well stimulation technique, applying a blend of defoaming and demulsifying surface active agents with a bullhead squeezing technique, has proven to be successful in the Cymric and McKittrick fields, California. The cost of incremental oil gained is less than $1.00 per barrel.

SPE Members Abstract Damage to proppant pack and formation permeability can drastically decrease well production. In many cases the damage is due to inconsistent degradation of gelled stimulation fluids and residual filter cake on the formation face. Several methods have been employed with limited success to remove polymeric damage in an effort to increase well productivity. A new technique utilizing polymer specific enzymes has been developed to facilitate removal of polymeric damage. The new, environmentally safe, remedial treatment can be applied over a wide pH range and at temperatures as high as 300 F. Laboratory analysis has shown that multi-fold permeability improvements can be achieved through polymeric damage removal with the new system. A case study of several low productivity wells suffering from polymeric damage was conducted. Production histories and return flow analysis were evaluated to characterize the damage and guide the remedial treatment design. The case histories of several wells treated with the remedial polymeric damage removal treatment demonstrate multi-fold improvements in well productivity. INTRODUCTION AND STATEMENT OF THE PROBLEM Polymers are widely used in drilling, completion, and stimulation applications as additives to provide friction reduction, viscosification, particle transport, fluid loss control, and zonal isolation. The residual effects of the insufficient degradation of polymers utilized in drilling, completion, and stimulation fluids has been identified as a primary contributor to permeability damage. Damage to the formation and/or proppant pack permeability can significantly decrease the hydrocarbon deliverability and hence, impair well productivity. Guar-based polymers are used extensively in hydraulic fracturing applications to provide the necessary transport properties to deploy the proppant into the fracture. The polymers are typically too large to penetrate the formation matriX and, consequently, are concentrated within the fracture due to dynamic fluid loss during the pumping treatment and fracture volume reduction upon closure. These concentration phenomena result in the formation of filter cakes which are elevated concentrations of polymer deposited on the fracture face and within the proppant pack. The concentration of these filter cakes can range from about 5 to greater than 25 times the surface polymer concentration depending on the reservoir properties, treatment design parameters, proppant concentration, and location in the fracture. Filter cakes with polymer concentrations of this magnitude are of high viscosity, low permeability, and practically insoluble. P. 591

Abstract The petroleum industry and regulatory agencies are searching for alternative methods for treating drainwater from oil rigs. Membrane separation has proven to be an effective and economic alternative to conventional methods for oil-water separation. Drainwater from oil rigs may contain up to 5% oil in addition to different chemicals in varying concentrations. Drainwater typically is collected in a burner tank and burnt by flare to the atmosphere. This emission to air causes an unwanted environmental impact. The summer of 1992 was used to test membranes and gather design information through pilot studies for a full-scale separation plant for treating oily drainwater. The results from the pilot testing were encouraging and a full-scale membrane plant was designed, however, not yet manufactured. The membrane separation plant is tubular ultrafiltration (UF) and the pilot plant operation was on a batch basis with a volume reduction factor approaching forty. The UF membrane had a maximum permeate flux of around 300 l/m2/h at maximum 6 kg/cm2 inlet pressure and 3.8 m/s fluid velocity with a clean membrane. The flux typically dropped and approached 80 l/m2/h at the end of a day's operation. The retentate from UF separation was returned to the feed tank whereas the permeate was routed to the sewer. Design of a full-scale plant was performed using a flux value of 40 l/m2/h. Cleaning of the membrane was performed with 0.3% nitric acid at 45 C and the alkaline detergent Ultrasil 11 at 0.25% and 55 C. The membrane flux did not always fully recover after each chemical cleaning. A 200 mg/l Cl2 solution administered as sodium hypochlorite (NaOCl) would, however, restore the original flux. Introduction An emerging objective of environmental regulatory agencies is the virtual elimination of toxins from industrial and municipal effluents. Regulatory agencies and industries are developing a rational approach to selecting and using the most cost-effective options for ensuring this goal.