bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Oriented Perforations as a Sand-Control Method: A Field Case Study from the Varg Field, North Sea
Authors: Tronvoll Johan , Eek Arne , Larsen Idar , Sanfilippo Francesco 
Published: December 2007

Abstract
The Varg field located in the central North Sea started production during the fall of 1998. It is located in a complex compartmentalized structure with different pressure regimes. The reservoir quality is generally good exhibiting partly heterogeneous sands containing weak and soft layers and partly homogeneous high-permeable and weak sand bodies. The field stresses are complex due to a number of faults, and indications of stress field rotations in wells in the proximity of faults have been observed. Precise mapping of the stress field has not been possible. Well testing data showed evidence of sand production in one appraisal well, and sand production indications were seen in another well. A sand production risk analysis was conducted prior to completion of the wells, and the risk of sand production was judged substantial. Based on perforation stability computations, selective and oriented perforations were suggested as a method to minimize the sand production risk. A majority of the producers were completed using oriented perforations at 0-180 deg. phasing. Since then no serious sand production events have been reported to date even though reservoir depletion of more than 100 bar (1450 psi) has been experienced in most reservoir compartments. The paper describes the field history with respect to production rates, productivity and sand production, as well as the analysis methodology and input data acquisition. The potential of oriented perforations as a sand control method is discussed on the basis of the field case comparing theoretical computations with field data.
Influences of Ultrasonic Radiation on Asphaltene Behavior With and Without Solvent Effects
Authors: Shedid Shedid A. , Attallah Saad R. 
Published: December 2007

Abstract
Asphaltic crude oils have caused serious problems in the oil industry all over the world. The major objectives of this experimental study are to investigate the influences of ultrasonic radiation on the behavior of asphaltene in the UAE crude oil, with considerations of temperature and solvent concentration effects. To achieve the goals of the study, two sets of experiments were undertaken. In the first experimental set, many identical crude oil samples having initial asphaltene content of 1.76 wt. % were subjected to different time intervals of ultrasonic radiation. Viscosity of these oil samples was measured under different temperatures. In addition, microscopic images of the centrifuged oil samples and Differential Thermal Analysis (DTA) of extracted asphaltene clusters were carried-out. In the second set of experiments, asphaltic oil samples of different solvent (toluene) concentrations were subjected to different intervals of ultrasonic radiation and under different conditions of temperature. Again, variation of oil viscosity with temperature was measured.
The results showed that subjection of the crude oil to ultrasonic radiation decreases the size of asphaltene clusters. Consequently, this effect increases the suspension of asphaltene in the crude oil and reduces/prevents its tendency to precipitate at 10 minutes or more radiation time. Furthermore, the results indicated that the use of ultrasonic radiation with toluene solutions increases the solubility of asphaltene in the crude oil at 10 minutes or more ultrasonic radiation time, but with more reduction in oil viscosity than that one with non-solvated oil. The application of the obtained results of the study could have real impact on the future development of simulation models, prevention of asphaltene precipitation and elimination, or at least minimization of the expected problems of asphaltene deposition.
Assessment and Diagnosis of Inorganic Scaling Potential Using Near-Infrared Technology for Effective Treatment
Authors: Ohen Henry A. , Williams Lee E. , Lynn Jack D. , Ali Liaqat 
Published: December 2007

Abstract
Inorganic scaling is a predominant formation damage mechanism in most producing and injection wells worldwide. Scales are deposited from oilfield brines when there is a disturbance in thermodynamic and chemical equilibrium. The degree of super saturation caused by the disturbance in equilibrium can be increased to result in scaling by changes in fluid composition through adverse mixing and by changes in temperature and pressure.
Although a few cases have been reported of non-water producing oil wells that produced scales, typically oil field scaling accompanies water production. Scaling problems during well development and supplemental fluid injection are primarily due to mixing of two incompatible fluids, whereas production related scaling is typically controlled by pressure and temperature. Acid or any common solvent cannot easily remove some types of scales like barium sulfate (BaSO4), which readily incorporates radioactive radium in its structure. Therefore detection and prevention is critical wherever any precipitation or co-precipitation that includes BaSO4 may be taking place. As severity of scaling is controlled by temperature, pressure and composition, the key to the detection, prevention and effective treatment is a methodology to determine at what conditions in the reservoir or at what point in the well the scales are precipitated and deposited and also determine the type of scale. This is important because sometime scales can be forming at a point in the well bore without showing up at neither the surface or at the sand face.
Near infrared (NIR) technology has been extensively used in detecting the organic scales such as asphaltene deposits. To the best of our knowledge, this study presents the first extensive use of NIR technology to diagnose inorganic scaling problems.
This paper presents several examples where NIR technology has been used to detect the onset of inorganic scale as a function of pressure depletion at reservoir temperature for water from different fields. We also show how the NIR technology has been used to determine the effectiveness of various commercial inhibitors at reservoir conditions. We also present further screening of the inhibitors (selected based on the results of NIR tests) to determine their effective use in the field and the design of the inhibitor treatment for the producing wells.
Specific Fluid Requirements for Successful Coiled Tubing Fracturing Applications
Authors: Cawiezel Kay E. , Wheeler Richard S. , Vaughn David R. 
Published: December 2007

Abstract
The recent success of coiled tubing fracturing in shallow wells has increased interest in using coiled tubing for fracturing deeper and hotter wells. Industry efforts need to now focus on understanding what properties of a fracturing fluid are required to successfully carry proppant at high rates through the coiled tubing, fracports, perforations and into these deeper formations. The key performance requirements of a coiled tubing fracturing fluid for deeper wells are low friction pressure and adequate proppant-carrying capability after exposure to high shear zones and higher temperatures.
This paper summarizes the results of pilot and field scale testing that led to the development of an optimized coiled tubing fracturing fluid. Results show that polymer-based fracturing fluids can be controllably delayed to have low friction pressure through the curved coiled tubing unit and straight tubing. However, results also show that fluid stability can be significantly reduced when pumped through small diameter tubing followed by high shear zones such as fracports and then perforations. Results demonstrate that correct fluid choice and fluid optimization are required to meet proppant transport requirements. For coiled tubing fracturing to be successful, the fluid and treatment design recommendations should balance the friction pressure limitations with the fluid stability limitations.
Fracture Stimulation of the Morrow Formation with Crosslinked Methanol: A Case History
Authors: Malone Mark R. , Nelson Scott G. , Greenlees William M. 
Published: December 2007

Proposal
In recent years several papers have been written on the merits of fracture stimulation with crosslinked methanol. While crosslinked methanol has been available to the industry since the late 1980's, only in recent years has it been successfully and routinely utilized in the continental United States. In areas such as the Permian Basin it was thought that the best application for crosslinked methanol would be in older wells, or in new wells drilled in under-pressured Morrow reservoirs. It was not until the case history wells in this study had been treated that the fluid was proven to be successful on new and relatively undamaged Morrow reservoirs.
This paper will discuss the fluid system with focus on recent refinements in fluid chemistry. Special attention will be given to standard procedures implemented to ensure the system is pumped safely. An overview of the reservoirs where crosslinked methanol has been applied successfully, along with treatment parameters will be discussed. Finally, a production study of the case history wells relative to offset Morrow producers will be reviewed.
Nondamaging Viscoelastic Surfactant-Based Fluids Used for Acid Fracturing Treatments in Veracruz Basin, Mexico
Authors: Artola Pedro , Alvarado Oscar , Huidobro Efrain , Salmorán Angel 
Published: December 2007

Abstract
For the last eight years acid fracturing stimulation has been performed in the Veracruz basin to increase gas production in naturally fractured carbonate formations. Several techniques have been proved to enhance the results of these jobs, including the diverting technique and the application of nondamaging viscoelastic fluids technology specifically a self- diverting viscoelastic based acid system and a polymer-free viscoelastic surfactant gel for fracture initiation and propagation.
This paper presents the results of successful acid fracturing treatments recently performed using nondamaging viscoelastic surfactant-based fluids to increase gas production from naturally fractured carbonate formations.
Most of the wells drilled and completed in the carbonate formations of cretaceous age in Veracruz basin do not flow naturally because of low matrix permeability and drilling/completion fluids damage. Therefore, acid fracturing treatments are necessary to produce these wells at economical rates.
The objective of these treatments is to increase gas production by creating a deeply etched fracture that will bypass the damaged zone and connect to the network of natural fractures and/or fissures. The etched fracture length affects well performance in low-permeability reservoirs; increased fracture length should result in greater production response. The use of nondamaging viscoelastic fluids is necessary to obtain longer effective etched fractures. Combining this with the properties of a viscoelastic diverting acid will significantly increase fracture conductivity as well as the effective stimulation of all perforated intervals.
The fluids were combined by using a pumping technique that consists of alternating stages of nonreactive fluids, reactive fluids and diverter fluid to reduce wormhole creation at the nearwellbore area and increase etched fracture length.
Four field cases are presented in this paper. In three, multiple intervals were treated, resulting in longer etched fractures as deduced from after-treatment production response and radioactive tracer logs. In the fourth case, not all the intervals were effectively stimulated because diversion was not used.
Acoustic Removal of Colloidal Particles From Berea Sandstone
Authors: Poesio Pietro , Ooms Gijs 
Published: December 2007

Abstract
During the production of oil from a reservoir, permeability decrease due to fouling particles in the near well-bore region leads to a significant decline in productivity. Several techniques (acid treatment, hydraulic fracturing) have been used to overcome this problem, but many drawbacks make them unattractive (they are expensive or environmental unfriendly, for instance). A relatively new technique has been proposed: the ultrasonic irradiation of the near well-bore region. This technique is not always successful and before applying it, a more fundamental investigation is needed. To date, only few experimental data are available and a more systematic investigation is required prior to using the techniques effectively. We focus our attention on removal of fine clay particles in Berea sandstone by high-frequency acoustic waves. We designed an experimental set-up where down-hole conditions (pressure of 180 bars and 80°C) are simulated and where we can control independently all the relevant parameters. Two acoustic horns are used: 20 kHz and 40 kHz, with a maximum power of 2 and 0.7 kW respectively. The influence of several parameters has been tested; an increase in temperature produces a better effect on the cleaning, since the particles structures become more instable as a consequence of the increase of electrical repulsion and, at the same time, the wave penetration increases. Pressure is noted to have no effect above the cavitation point: if the tool operate above 120 bars no effect of pressure is observed, on the contrary lower pressures induce cavitation and then most the acoustic energy is lost before reaching the core. The key parameter of an optimal use of the technique turned out to be the flow rate: as the flow rate decreases the cleaning effect increases: this effect can be explained by the fact that high flow rate keeps, more strongly, the fouling particles into the pore throats. The effect of the initial permeability is investigated together with the effect of the initial level of fouling. A study on the most effective use of a certain amount of energy is carried out. As conclusion, we now have a better understanding of the influence of the relevant parameters on the ultrasonic cleaning.
An Improved, One-Step Cleanup System for Removing Mud Damage in Horizontal Wells
Authors: Ali Syed , bte Ahmad Atikah , Rae Phil , Gilmore Todd 
Published: December 2007

Abstract
Many wells are damaged in the course of drilling and workover by the use of drilling muds, drill-in fluids, and kill-pills that contain, amongst other things, polymeric constituents. The latter may consist of a single polymer or may consist of mixtures of polymers in aqueous solution/suspension which are added for the purposes of viscosification, leak-off control, lubrication, etc. Typically, the polymers used include xanthans, starches, celluloses, guars, and derivatives of these main groups. In addition, most of these fluids contain some form of particulate to impart density and to improve fluid-loss control, commonly calcium carbonate.
It has been established that well productivity can be significantly impaired by the use of these mixtures, due to the persistence of residues. Their removal can result in substantial improvements in production. There are those who believe that such damage can be removed simply by applying sufficient drawdown but, generally, chemical methods using acids and/or oxidisers like sodium hypochlorite are used. Neither of these approaches is effective alone at removing all the damage caused by cake components. This often necessitates multistage soak treatments, with large volumes of treating fluid, in extended reach wells. Such procedures complicate the operation and cause additional expense due to the time involved.
This paper describes a novel chemical system, capable of removing all common mud polymers while, simultaneously, dissolving the calcium carbonate and accomplishing this in a single one-step treatment. These systems are safe and effective and can remove essentially 100 percent of all residues, restoring permeability to its original level.
Evaluation of a New Barite Dissolver: Lab Studies
Authors: Nasr-El-Din H. A. , Al-Mutairi S. H. , Al-Hajji H. H. , Lynn J. D. 
Published: December 2007

Proposal
Barite is a common weighting agent used for oil well applications. It is commonly used to provide adequate weight to control downhole pressures in drilling slurries. Since it is used for control of pressure, it is a common source of formation damage, especially in deep, hot formations where drilling fluid weights exceed 17 ppg. Although alternatives do exist for barite, (e.g., formate drilling fluids) they are significantly more expensive, and not available on a rapid turnaround basis as in emergency situations required by well control operations. Once damage has occurred, remediation is a very difficult proposition. Barite is not soluble in typical oilfield inorganic acids used in stimulation. The most common methods of remediation are fracture stimulation and/or deep perforations. The use of these methods can remediate the problem, but at high cost. Also, since the well productivity cannot be evaluated prior to stimulation operations, a poor quality well cannot be identified until a significant investment has been made.
The most common chemicals currently in use to address this problem are "barite dissolvers". These agents are all strong metal ion chelators. Aminopolycarboxylic acids (e.g., EDTA) and similar reagents have been used with low success rates.1 Recently, hydroxylaminopolycarboxylic acids were introduced, but to the best of the author&#39;s knowledge was not extensively used in the field.2
This study investigates a new barite dissolver and compares its performance with other commercial dissolvers. The new material is a proprietary dissolver supplied in a liquid form. This study investigates the dissolving capacity, and evaluates the effectiveness of the dissolver by conducting coreflood tests. These tests were conducted using sandstone cores obtained from a deep gas well (300°F). The effectiveness of the dissolver was followed by measuring the concentration of barium in the core effluent. Unlike other barite dissolvers, the new chemical is shown to be very effective in restoring the permeability of damaged cores. The new chemical does not require long soaking times, and does not induce fines migration due to chemical means.
A New Effective Stimulation Treatment for Long Horizontal Wells Drilled in Carbonate Reservoirs
Authors: Nasr-El-Din Hisham , Al-Habib Nabil S. , Al-Mumen Adib A. , Jemmali Mohammed , Samuel Mathew 
Published: December 2007

Abstract
Effective matrix acidizing of horizontal and multi-lateral wells is a very difficult task. Unlike vertical wells, horizontal wells can extend several thousands feet in the formation. Reservoir heterogeneity and the length of the horizontal leg make acid placement and diversion a real challenge. In addition, the low drawdown encountered in horizontal wells results in longer times to lift the spent acid from the well.
To achieve better acid diversion in horizontal wells drilled in carbonate reservoirs, a viscoelastic surfactant-based self-diverting acid system was utilized. The components of this new system are HCl and a viscoelastic surfactant. The acid dissolves calcite and dolomite minerals and produces calcium and magnesium chlorides. The increase in pH forces the surfactant monomers to form rod-shape micelles. The produced chloride salts further stabilize these structures, especially at high temperatures. The rod shape micelles will significantly increase the viscosity of the acid, diverting the acid into tight un-stimulated zones.
More than forty-five horizontal wells with openhole completions were successfully stimulated in two offshore oil fields in Saudi Arabia using the new treatment system. There is a water cap 30 feet away from these openhole (OH) sections in one of the fields, and growth of any dominant wormhole into these sections could increase water production. The wells that used the new treating fluid produced an average of 1,600 barrels of oil per day more than conventionally treated wells, with no indication of water production. Field results (pre and post oil and water production rates and FWHP) demonstrate the effectiveness of the new system to matrix acidize long horizontal wells with openhole completions. The simplicity of the system makes it the fluid of choice, especially in offshore environments. The absence of metals in this system helps in minimizing sulfide precipitation in sour wells.
Decision and Risk Analysis Study of the Injection of Desalination By-products into Oil- and Gas-Producing Zones
Authors: Burnett David B. , Veil John A. 
Published: December 2007

Abstract
When reverse osmosis (RO) is used to desalinate brackish water feed streams, a small but significant amount of the brine is discharged as a "reject" stream from the RO unit. This brine contains concentrated dissolved salts and other materials. Disposing of this brine concentrate for traditional RO processes can represent a significant fraction of the cost of operating the unit to recover fresh water. Coincidently, in the oil and gas industry, high salinity brines are routinely injected into formations for pressure maintenance and secondary recovery by water flooding. If water from desalination operations could be injected into these oil- and gas-containing formations, the estimated cost savings could be as much as 30% of the cost of operating the desalination unit. This represents a significant cost savings for RO technology that would make fresh water available to communities in need of this valuable resource.
To provide a comprehensive assessment of the perceived benefits compared to the possible hazards of this practice, we use risk analysis theory to define this process in more detail. The potential for formation damage, reduced injectivity, produced water scaling, and environmental impact is evaluated through comparison with traditional waterflood compatibility studies. We also provide an analysis of how state and federal Underground Injection Control (UIC) rules may be used to regulate injection of RO reject brines. The risk analysis study goes beyond classical decision analysis theory to address the "triple bottom line" economic, environmental, and societal benefits afforded by the process and provides a roadmap to gather quantifiable information for regulators, businesses, and community leaders who might consider this technology.
OTTER North Sea Subsea Field Development: Sand Control Strategy and Implementation
Authors: Profinet J. , Petit G. , Goyalon D. , Horn M. , Furgier J-N. , Coudeville F. 
Published: December 2007

Abstract
The OTTER field is the first to use a 'dual ESP' completion in a subsea field, the project was developed by TOTAL and its partner's in the Brent sand reservoir, in the UK North Sea sector.
This development consists of three horizontal open hole oil producers and two cased hole water injectors, drilled from a combined drilling template and production manifold and tied-back to the EIDER host platform 21km away. Each oil producer can deliver up to 20,000 BOPD, the field has been on production since October 2002.
A risk of sand production during the life of the field was identified, therefore downhole sand control was deemed necessary.
Well longevity has a major impact on the global project economics. Achieving and maintaining sand free production through optimal completion design was therefore critical to the overall success of the development.
This paper describes the strategy adopted and the factors considered in the development of the sandface completion optimised for the field life. Decisions on the sand control technique decisions were made while drilling the well based on cuttings particle size analysis: too small would have lead to open hole gravel pack. By eosteering the horizontal drain to stay within the most competent a sand body it would be possible to use a Stand Alone Screen completion, which was considered as the best option (cost, risk, and efficiency). The operationnal experience gained and lessons learnt on the first well contributed to the design enhancements required for completion of the following horizontal wells.