bluuebunny/crossref_metadata_2025_split huggingface dataset:
4D Seismic and Through Tubing Drilling and Completion Wells Extend Life on the Gullfaks Field
Authors: Todnem Annick Chazy , Arnesen Linn , Gaasø Rune 
Published: December 2007

Abstract
The Gullfaks Main Field is one of the largest oil fields in the Norwegian sector of the North Sea. Production started in 1986 and reached a peak in 1994. Today approximately 90 % of the base reserves have been produced from this mature field. Locating remaining oil reserves is therefore a challenging and important task for the future of Gullfaks. The reservoirs are comprised of middle and early Jurassic sandstones, possessing overall excellent reservoir properties. The structural setting of the field is complex, and represents one of the main factors of uncertainty concerning the drainage of the field. The paper describes how multiple time-lapse seismic (4D) have proven very accurate in identifying undrained oil pockets in the Brent Group. The importance of 4D/4C in the wells drilled is estimated to represent a reserve oil volume of approximately 4 Mill. Sm³ per 2004, (25 Mill. Sbbl). TTD&C (Through Tubing Drilling and Completion), being a more flexible and less expensive technology, has also been crucial in reaching smaller oil pockets on the Gullfaks Main Field. The potential offered by these technologies has been optimized by multidisciplinary teamwork on Gullfaks, thus creating synergy and flexibility. These three key elements have contributed to reverse the oil production decline, establish a new plateau, reduce costs and increase profit.
Tortuosity Factors for Highly Tortuous Wells: A Practical Approach
Authors: Samuel G. Robello , Bharucha Kaiwan , Luo Yuejin 
Published: December 2007

Abstract
Tortuosity is one of the critical factors to be considered for complex directional well trajectories, complicated build rates, precise steering in thin reservoirs and extended reach wells. When planning a well, wellpath modeling commonly generates smooth curves, whereas an actual well contains severe doglegs and other irregularities. Determining the tortuosity factors to apply in the well path is always a challenge during the planning phase. Presently no quantification method is available and field tests have shown that the present calculations gravely underestimate the drillstring torque and drag values for highly deviated, tortuous deep wells. Problems mostly occur when the drillstring lies in a strongly curved wellpath. In the long transitional region that covers most of the operational range in field applications, the conventional equations used for torque and drag calculation results in underprediction. Due to increased extended and steered wells the torque and drag calculations need correction to take care of the tortuous effects of the wellbore. This paper addresses the adverse impact of the torque and drag calculations in highly tortuous wells and presents an approach to calibrate the tortuosity factors whereby the accuracy of the calculations is enhanced. The methodology uses actual survey data and known surface hook loads for different operating conditions, such as tripping in, tripping out, and rotating off bottom, to arrive at appropriate friction factor values that can be used further in torque and drag calculations. Once the friction factors for both cased hole and open hole are determined, sensitivity analyses can be done on the planned survey. Appropriate tortuosity values are derived at by comparing predicted results with the field driller's data. This paper also describes four methods, Sine Wave, Random-Azimuth, Random-Inclination-Azimuth and helix used to calibrate the tortuosity factors that better represent the actual curved wellbore. The simple guidelines are presented along with two field examples from Gulf of Mexico. The simple, pragmatic approach provides a comprehensive framework for calibrating tortuosity values for complicated tortuous wellpaths.
Triaxial Creep Tests in Salt Applied in Drilling Through Thick Salt Layers in Campos Basin-Brazil
Authors: Maia C. A. , Poiate J. E. , Falcão J. L. , Coelho L. F. M. 
Published: December 2007

Abstract
The presence of salt structures in prospects for oil and gas exploration is, in itself, a factor that increases the probability of success due to favorable conditions for the hydrocarbons generation and trapping. However, many operational problems such as stuck pipes and casing collapse have been reported by the industry when drilling through those salt layers.
Historically, in Campos Basin – Brazil, several deep wells have been drilled through thick salt intervals. Up to the 90', the lack of a reliable ways to predict salt behavior at high temperatures and high differential stresses led to very high costs and even loss of wells.
In this paper we present a methodology for mud weight and casing design and also to define the drilling strategies employed for drilling through thick salt layers. The numerical simulations to evaluate the creep behavior of salt submitted to high differential stresses and high temperatures were done through the applications of an in-house finite element code developed. To calibrate the model, triaxial creep tests in salt samples were performed to evaluate and isolate reological properties to represent its creep behavior under different differential stresses and temperatures. It was verified that numerical and experimental results matched and had a fine conformity.
A recent application of this methodology in a sub salt well in Campos Basin allowed us to drill the salt without a problem. Results obtained by numerical simulations were used to predict the evolution of the well closure with time for various mud weights and analyze several alternatives of casings capable of supporting salt creep. As a result, stuck pipe and casing collapse were avoided and drilling costs reduced.
Evaluation Methods for Suspended Solids and Produced Water as an Aid in Determining Effectiveness of Scale Control both Downhole and Topside
Authors: Jordan M. M. , Johnston C. J. , Robb M. 
Published: December 2007

Abstract
The formation of mineral scale (carbonate/sulphate/sulphide) within the near well bore; production tubing and topside process equipment has presented a challenge to the oil and gas industry for over 50 years. Chemical methods to control scale have been developed including scale squeeze treatments and continual chemical injection. A key factor to the success of such treatment is the understanding of chemical placement and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs and more recently probes have been developed which increase the rate of evaluation/interpretation. All these methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. Evaluation of suspended solids in terms of amount, mineral type, composition and texture has been used along with brine chemistry to improve our understanding of the location of scale formation within production environments. This paper outlines the experimental methods developed and will site examples from the North Sea of the use of suspended solids analysis by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced brine. The combination of these methods has improved integrated scale management in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and topside scale control challenges vs. separation problems.
The publication of this method with clear examples of the value it can bring to an integrated scale management program for a field throughout its life cycle will benefit both emerging deep water (evaluation of placement) and more established oilfield operations (reducing chemical costs).
Study of Scale Inhibitor Reactions in Precipitation Squeeze Treatments
Authors: Tantayakom V. , Fogler H. S. , Chavadej S. 
Published: December 2007

Abstract
One of the most effective methods used in oilfield operations to prevent or limit scale formation is the use of precipitation squeeze treatments. A fundamental understanding of scale inhibitor precipitation is important in designing squeeze treatments in oilfield. Diethylentrilopentrakis (methylenephosphonic acid) (DTPMP) and Aminotri (methylenephosphonic acid) (ATMP), two scale inhibitors used in the petroleum industry were used as model inhibitors in this study. Inhibitor concentration, solution pH and the presence of salts in the produce fluids were found to have a significant impact on the placement of scale inhibitor and result in the formation of precipitates with markedly different properties. The amount of inhibitor precipitated decreases with the addition of Mg suggesting that the presence of Mg decreases the effectiveness of Ca-Inhibitor precipitation. A model of induction time was applied to inhibitor precipitation. Long induction times allow transport of the inhibitor fluids without inhibitor precipitation and damage to near-wellbore regions. The competitive reaction among the soluble salts in the formation water with the scale inhibitor was found to delay the precipitation rate of scale inhibitors. The nucleation kinetics of Ca-ATMP is accurately described by classical nucleation theory. The presence of different salts such as LiCl, NaCl, KCl and MgCl2 in solution was found to increase the surface free energies, thereby delaying the inhibitor nucleation and growth.
Use of Nitrate to Mitigate Reservoir Souring in Bonga Deepwater Development Offshore Nigeria
Authors: Kuijvenhoven C. , Bostock A. , Chappell D. , Noirot J. C. , Khan A. 
Published: December 2007

Abstract
The Bonga field located in deep water off the Nigerian coast needs pressure support to effectively recover the hydrocarbons. The strategy is to inject 300k bwpd seawater from the start of oil production. During the field development in 1999 it was concluded that Bonga was expected to suffer from reservoir souring, and that mitigation would be necessary.
Initial data gathering indicated that the expected H2S content resulting from reservoir souring was not expected to exceed 50 ppm(v) in the gas phase. Initially nano-filtration to reduce the sulphate level in the seawater was identified to mitigate reservoir souring but due to the high CAPEX costs it was dropped and as there were no other proven mitigation techniques available, it was decided to operate without mitigation. The strategy for this project was to let the reservoir sour and handle the H2S with sour service materials and scavenging facilities topside. The facilities were designed to handle a maximum level of 50 ppm(v) H2S.
As detailed design progressed and more field data became available, doubts were raised on the suitability of this approach. The strategy to let the reservoir sour and handle the H2S at surface was re-evaluated in 2003. It was found that H2S levels are likely to exceed 50 ppm(v). Since then a new strategy with mitigation was adopted. Several operators had verified that nitrate injection is an effective mitigation technique to control H2S development. However, to date the main application for nitrate had been the reduction of H2S in already sour fields and the experience for the use of nitrate from the start of the water injection scheme was limited.
This paper presents a detailed evaluation of the potential for reservoir souring due to biogenic reservoir souring in the Bonga field, and work done to predict H2S levels. The paper will also focus on the selection of nitrate as a mitigation method.
Deep Downhole Chemical Injection on BP-Operated Miller: Experience and Learning
Authors: Wylde J. J. , Williams G. D. M. , Careil F. , Webb P. , Morris A. 
Published: December 2007

Abstract
The BP operated Miller field poses a unique chemical challenge as it has arguably the harshest oilfield scaling regime in the North Sea, if not the world. An average of 3-4 squeeze treatments per week are performed across the online wells creating tremendous operational, chemical and logistical challenges. This produces the ideal environment to evaluate new technologies and engineering solutions in an attempt to increase the wells' overall efficiency.
Deep downhole chemical injection (DDHCI) was installed on well A26/08 and brought online during July 2003. The Miller DDHCI is unique to the industry as it allows the injection of a scale inhibitor at the perforations via a tail pipe essentially protecting the whole of the tubing from scale deposition. This approach has the potential to reduce the need for additional scale control via squeeze treatments.
Much emphasis has been placed on the efficiency of scale protection DDHCI offers. A year of flowing the well under the protection of the continuous injection chemical has yielded much information about the nature of the chemical delivery and inhibitor efficiency. Much has also been learnt about the pumping hardware required to ensure continued performance. Further information has been provided by two intensive sampling exercises which have allowed independent analysis for the squeeze chemicals and the injected chemical.
Recovery of Oil from Drilled Cuttings by Liquefied Gas Extraction
Authors: Seaton S. , Hall J. 
Published: December 2007

Abstract
It has long been accepted that non-aqueous invert emulsion drilling fluids provide improved drilling performance compared to traditional water-based systems. Use of diesel, mineral oil, and more recently, synthetic materials such as olefins and paraffins as base fluids has gained global acceptance. However, the disposal of these materials and associated drill cuttings can generate environmental concerns. The capability to remove oil or synthetic oil from the cuttings before disposal can significantly reduce the long-term environmental effects of disposal. In addition, effective recovery of costly synthetic fluids could improve the overall economics of drilling.
This paper summarizes research efforts into development of a technique that uses liquefied hydrocarbon gases as solvents to extract oil from cuttings. The laboratory data presented shows that a wide variety of fluids can be efficiently recovered from cuttings. Residual oil on cuttings levels can be reduced to concentrations exceeding the standards typically required for disposal or discharge, with no thermal energy requirements and recycling of the solvent phase and recovered fluid. Risk assessments indicate that the technique can be safely applied at both onshore and offshore operations.
West Seno Deepwater Development Case History–Production Chemistry
Authors: Gallup D. L. , Smith P. C. , Star J. F. , Hamilton S. 
Published: December 2007

Abstract
The West Seno field is located in the Makassar Strait PSC offshore East Kalimantan, Indonesia about 60 km offshore in ~3,200 ft of water. Field development consists of a tension leg platform (TLP), a floating production unit (FPU), and two export pipelines tied back to existing onshore infrastructure. Production commenced in August 2003, and Phase 1 of the project has now ramped up to over 45,000 BOEPD.
The field presents a number of production chemistry and flow assurance challenges, the most serious of which is an unusual emulsion. Organic acids in West Seno crude oils react with bicarbonate rich produced waters to form sodium and other metal carboxylates. These metal carboxylates are "soaps", which tend to linger at water/oil interfaces and afford highly stabilized brine-in-oil ‘forward’ emulsions. Conceptually, soap-stabilized emulsions should be easy to break, as one simply adds a demulsifier to reverse the soapforming reaction and allowing the phases to separate. Unfortunately, the emulsions are constantly undergoing shear, by various items of standard production process equipment, helping to re-emulsify partially separated fluids. Furthermore, in the deepwater environment, produced fluids tend to cool significantly, thereby losing the benefit of heat-induced demulsification and causing waxes to precipitate. Also, fine solids (formation fines, residual drilling mud solids, etc.) typically accompany production, further adding to emulsion stability. Although acid demulsifiers have been successfully applied at West Seno, due to the complex nature of the emulsions with multiple stabilizers identified, a finite residence time is still needed for phase separation, which creates a potential production bottleneck. Emulsions must not be over-treated since injection of acidic chemical induces corrosion, and the phosphoric acid portion of the demulsifier reacts with calcium in the brine to form hydroxyapatite and vivianite/polyphosphate scale solids.
To destabilize the emulsions it is important to dehydrate the oil as early as possible with heating, minimize shearing and reduce the introduction of solids to the production stream by insuring an efficient mud displacement prior to well completion. Desander hydrocyclones are used on the FPU upstream of deoilers, and regular sand jetting of the main separator is necessary. Other important production chemistry/flow assurance issues that are being addressed include: gas hydrate inhibition,produced water treatment with reverse emulsion breakers, flocculants and solids wetting agents,microbiological control in FPU "off spec oil" and off spec water" surge tanks, andcompatibility of treatment chemicals and adverse effects on the soap emulsion.
Evaluation of the Effect of the Water Formation Salinity in the Performance of Gels for Water Shutoff
Authors: Llamedo M. A. , Fernández I. J. , Pérez D. L. , Rauseo O. , Valero E. , Espinoza J. 
Published: December 2007

Abstract
In this work a gel of an acrylamide based polymer crosslinked with organic reagents was studied. This gelling system was one of the commonly used in water conformance treatments. Once formed in bottle tests the gel was placed in contact in several proportions with water of various salinities. The tests where carried out at 266°F, and the changes were registered as a function of time. It was found that the gel swelled until a constant final volume. This value depende the difference between the salinity of the water used to prepare the gel and the added water. The performance of this gel in porous media was evaluated by coreflood experiments in Berea sandstone at 266°F with water prepared with the same compositions evaluated in the bottle tests. The results indicated that the RRF values are lower if the salinity of the reservoir water is similar to water salinity used to prepare the gelling mixture; while the Residual Resistance Factor (RRF) increased if the salinity of the reservoir water was much higher than the salinity of the preparation water.
These findings show that it is important to take into account the difference between the water salinity used to prepare the gelling system and the water reservoir in the design of water conformance treatments with polymeric gels.
Effective Chemistries to Control SRB, H2S and FexSy Problems
Authors: Dickinson A. , Peck G. , Arnold B. 
Published: December 2007

Abstract
Sulfate reducing bacteria (SRB) exist in many oilfield production systems. Their metabolic by-product, hydrogen sulfide (H2S), is corrosive and also combines with iron ions to form iron sulfide (FexSy) solids. The corrosive and plugging effects of these materials can severely impact operations and costs of a water injection system. Their control can present a significant challenge for the system operator.
This paper reviews the field performance of three different chemistries to control SRB, associated H2S, and FexSy solids. These chemistries include a mixed amine biocide, acrolein, and anthraquinone. Each chemical is applied to a specific part of the oilfield production system to effectively treat for biogenic sulfides. These locations include: at the producing wells, at the waterplant and downstream water injection system and a slop handling system. Each product was selected for its unique chemical properties that best resolved the specific field problems.
The results of this study indicate the following:
Periodic batch treatments of numerous artificial lift wells with a mixed amine biocide reduced the sulfides in the mixed produced fluids entering the waterplant inlet by 90%. An acrolein batch treatment program reduced total suspended solids levels at the waterplant outlet by 87% and improved other water quality parameters in the downstream injection system. Anthraquinone batch treatments into the slop handling system reduced sulfide levels by 95%.
Improving Injector Efficiency Using Streamline Simulation: A Case Study of Waterflooding in Saudi Arabia
Authors: Ghori S. G. , Jilani S. Z. , Vohra I. R. , Lin C. 
Published: December 2007

Abstract
The 3-D streamline simulation approach is complementary to finite difference simulation techniques. One of the main advantages of streamline simulation is its ability to display paths of fluid flow and to calculate rate allocation factors. These capabilities have been utilized to improve operating and development plans for a water-flood project.
An incremental development plan for a Saudi Arabian carbonate reservoir that included the drilling of several horizontal injection/production wells is discussed in this paper. A few wells had already been drilled at the start of this study. The main objectives of this study were to improve well placement and injection rates using streamline simulation.
During the course of the study a few limitations of the streamline simulator have been encountered, highlighted, and discussed. The results showed that streamline simulation is still in the development stage in highly compressible systems. It is tricky to follow field/group rate targets and limits along with the individual well rate targets in prediction mode.
Prior to the optimization phase of the study, the streamline simulator was successfully applied to reproduce the historical performance of the reservoir during primary depletion in the absence of any water injection.
Valuable information was obtained from streamline simulation; a) distribution of injected water to associated producers, b) water loss to the aquifer, c) percentage of oil produced due to each supporting injector, and d) amount of water cut attributable to each supporting injector.
Quality indicators were generated to gauge injection efficiency for each well using plots of injection rate vs. offset oil/liquid production rate. Relatively poor performance injectors were identified from this plot. Injection allocation rates and injector drilling locations were then modified through a series of simulations to improve their efficiency. This led to an improved injection pattern in the studied reservoir.