bluuebunny/crossref_metadata_2025_split huggingface dataset:
Deployment, Monitoring and Optimisation of a Combined Scale/Corrosion Inhibitor within a Subsea Facility in the North Sea Basin
Authors: Jordan M. M. , Archibald I. , Donaldson L. , Stevens K. , Kemp S. 
Published: December 2007

Abstract
This paper presents field results and lessons learned from a North Sea field where a combined scale and corrosion inhibitor has been applied using a single formulation to control both the deposition of scale and associated corrosion. The Galley field is a subsea development within the UK sector of the North Sea. The use of a single product has facilitated a reduction in the number of umbilical lines to be used to provide flow assurance on the subsea flow lines and process of this facility.
The paper outlines the problems encountered when the initial formulation was deployed in the field and the steps taken to develop and monitor an improved formulation. Problems that can affect product application in a subsea environment, including deposition of suspended solids within the chemical, hydrate formation, incompatibility of the chemicals with umbilical material and produced fluid, will all be addressed. The laboratory methods used to select the product along with measurement methods used in the field are also discussed. The validation of the laboratory selection methods in the field required the development of a monitoring program to establish base line control and to assess the degree of protection from scale deposition and corrosion across the process.
The changing physical conditions within the flow lines and across the topside process will be described, as well as the changes in brine chemistry within the field, as injection water breakthrough occurred. The use of novel real time monitoring, as well as water chemistry tracking and analysis of suspended solids within the produced fluids across the process will prove vital to the understanding of the efficiency of flow assurance within the processes was and how treatment rates and products could be optimised.
This paper will outline in detail the particular issues associated with chemical injection to a subsea facility, many of which are currently being developed in the Gulf of Mexico and is a good example of lessons learned and sharing of best practice from another oil basin.
Preventing Erosion and Erosion Corrosion Using Specialty Chemicals
Authors: Ramachandran S. , Bartrip K. A. , Menendez C. , Coscio S. 
Published: December 2007

Abstract
In the current paper the ability of corrosion inhibitors to retard erosion corrosion in both purely erosive environments and environments with erosion corrosion are studied. The study uses measurements based on weight loss. The method of application of the inhibitor is studied by using a specified concentration of inhibitor in the experiment, filming the metal coupon or by using sand that has been exposed to a specified concentration of inhibitor. For the experiments that are done in a purely erosive environment, extrapolation of the laboratory results is done using an equation developed in previous work.1 The extrapolation indicates that using inhibitors in erosive environments can allow producers to safely transport more fluid or gas through an existing pipeline system.
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

AbstractThe 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

AbstractThe 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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.