bluuebunny/crossref_metadata_2025_split huggingface dataset:
Engineered Application of a Weighted Fracturing Fluid in Deep Water
Authors: Bagal J. , Gurmen N. M. , Holicek R. A. , Gadiyar B. R. , Fredd C. N. 
Published: December 2007

Abstract
Over the past decade, operators in offshore fields such as the Gulf of Mexico and West Africa have increased their investment in deepwater projects. The trend is expected to continue in the future. For frac and pack operations in deep water, the industry is facing some particular challenges that limit completion options. A major challenge is the need to reduce the surface treating pressure to stay within current equipment operating limits. One solution is to increase the fluid density, thereby allowing for a reduction in the surface pressure while generating the same bottomhole pressure. However, higher fluid densities can also lead to higher friction pressures that may overcome the hydrostatic benefits. In addition, as the water depth increases, the travel time to the mudline increases, resulting in the need for extended crosslink delay times. Therefore, fluids that provide flexibility in density and extended crosslink delay times are required for effective treatment designs in deep water.
This paper describes a weighted, delayed crosslink polymer (WDC) fluid and engineering guidelines for its use in frac and pack applications. Sodium bromide is used as the weighting agent to provide higher densities (8.3 to 12.5 ppg) compared to conventional fluids. Additionally, the fluid has a delayed crosslink that can be controlled from 2 to 20 minutes, which helps in limiting the tubing friction.
Extensive laboratory testing was performed to ensure the technical feasibility and effectiveness of the WDC fluid. Tests included polymer hydration in brine, crosslink delay time measurements, rheology at bottom-hole static temperatures, shear sensitivity, fluid stability at mudline temperatures, breaker design, leakoff characteristics and matrix cleanup, proppant-pack conductivity, and friction pressure tests. Results demonstrate that the WDC fluid meets all performance requirements. It is stable at mudline temperatures down to 40 °F, and effective at bottom-hole temperatures of at least 250 °F.
An engineering simulator was developed based on completion characteristics to select the weighted fluid in cases where it can be beneficial. Example case histories are presented that demonstrate conditions under which weighted fluids provides a reduction in treating pressure. The WDC fluid has shown the ability to reduce the treating pressure by at least 20% depending on the wellbore configuration. The strong dependence of treating pressure on completion geometry, fluid density, and crosslink delay time necessitates evaluation of each treatment on a well-by-well basis to determine effective applications of weighted fluids.
Fracture Propagation, Filter-Cake Buildup and Formation Plugging During PWRI
Authors: Zaki K. S. , Sarfare M. D. , Abou-Sayed A. S. , Murray L. R. 
Published: December 2007

Abstract
Produced water reinjection (PWRI) offers an efficient and effective means of disposing of the PW waste stream and provides an opportunity for a water drive when applied during waterflooding. The required rate of produced water reinjection can be anticipated using the expected pore volume replacement ratio and water-cut estimated from the production forecast. Fracturing is likely to occur during produced water reinjection at voidage replacement rates. The extent (size) of the induced fracture(s) will significantly impact the waste disposal process. It is, therefore, necessary for well injectivity planning and fracture sizing to have an accurate estimate of pore pressure, the rock's mechanical properties and the minimum in-situ stress in the injection horizon. This collective information can be used to estimate the required injection pressure and the number of injectors throughout the production period. In addition, well planning and design will also benefit from predictions concerning the injector performance histories – and the length of the created fracture. Overall, the waterflood planning-cycle efficiency will be increased.
It is generally accepted that PWRI leads to plugging of fractures and damage of injection zone permeability1-2. The engineering issue faced by the operator is reduced to establishing the balance between two (2) competing mechanisms. The first mechanism is related to the well-injectivity improvement that may result from any fracturing associated with produced water reinjection. The competing mechanism results from plugging of the near crack-tip region and the impairment of reservoir performance (permeability) around the fracture caused by water contaminant invasion of the injection horizon.
The interplay between the reservoir rock properties and water quality parameters3-4 has been qualitatively discussed in some detail in the past. However, this paper will confine discussions to fracture propagation and its impact on well injectivity, under conditions of produced water reinjection in permeable reservoirs. Results of such analyses can provide estimates of filter-cake permeability and thickness, as well as the magnitude of permeability impairment around the fracture and the extent of the impairment zone.
Taking Nondamaging Fluids to New Extremes: Formate-Based Drilling Fluids for High-Temperature Reservoirs in Pakistan
Authors: Oswald R. J. , Knox D. A. , Monem M. R. 
Published: December 2007

Abstract
The use of low-solids, water-based reservoir drilling fluids has generally been restricted to fields with temperatures of less than 300°F, primarily due to the limitations of fluids in more aggressive environments. The Miano and Sawan fields in Pakistan are both classified as high temperature (up to 340°F BHST), and some wells have been recognised as requiring sand control for optimal production.The operator of this field is dedicated to the application of water-based muds in all activities to reduce the environmental impact of operations.
Based on these criteria and extensive laboratory testing for thermal stability and expandable screen (filter cake quality) compatibility, a formate-based, low-solids, reservoir drilling fluid was selected. The laboratory performance of the fluid will be confirmed by the performance in the world's first field application of high-temperature formate drilling fluid run with expandable screens.
A New Technical Standard for Testing of Heavy Brines
Authors: Javora P. H. , Berry S. L. , Stevens R. F. , Carpenter J. F. , Isaac D. D. , Dalton F. G. , Augsburger J. , Guy-Caffey J. K. , Tomlin M. , Jones T. A. , Malachosky E. , Prasek B. A. , Foxenberg W. E. , Freeman M. A. , Howard S. K. , Benton W. J. , Son A. , Eichelberger P. , Stark C. L. 
Published: December 2007

Abstract
A new technical standard has been developed for assessing the performance and physical characteristics of heavy brines used in completion, packer, and drill-in operations. This technical standard includes procedures for evaluating the density, specific gravity, clarity, amount of suspended particulate matter, crystallization point, pH, and iron contamination. It also contains a discussion of gas hydrate formation and mitigation, brine viscosity,brine crystallization at high pressures,corrosion testing, buffering capacity,and a standardized reporting form.
Openhole Gravel Packing in the Roaring Forties
Authors: Puyo P. , Bourgeois A. , Penno A. D. , Oliveira A. C. 
Published: December 2007

Abstract
TOTAL AUSTRAL operates the Carina and Aries fields, which are located in offshore Tierra del Fuego in the most southern region of Argentina. These fields are prolific gas producers and are being developed with a reduced number of wells with departures of up to 3.5 km at approximately 1000 m TVD.
This paper discusses the issues surrounding the TOTAL AUSTRAL Carina field development project and the innovative processes that were used to address these situations. Through careful planning,the processes selected to facilitate the completions were successful in achieving the project goals of the operator. These goals included not only the production of gas at relatively high rates from the shallow unconsolidated sand-stone reservoir at approximately 1000 m TVD but also minimization of impact to the environment.
To minimize cost and still accomplish the project goals, the wells were drilled from a single platform.
Unique Experience in Roncador Asset: A New Approach to Hard Drilling Conditions
Authors: de Meira D. C. Alves , de Barros L. P. Franco 
Published: December 2007

Abstract
During the last three years, Petrobras has experienced a sharp increase in the amount of ultra deep water operations. Moreover, most of its production comes from that challenging environment. Doing it well is a matter of company survival.
Petrobras' UN-RIO business unit Roncador asset, due to reservoir characteristics and production strategy, has implemented a unique configuration for its oil production and injection network. In summary, the Roncador asset decided to use pilot wells to tag the best positions within the reservoir.
By trying to re-use most of the pilot wells, the Roncador asset drills long horizontal sections, which are more than 1000m long. Drilling those particular wells has provided Petrobras with many lessons and approaches. It is a continuos improvement process. Nevertheless, big challenges are still on!
The present work pinpoints drilling experience and problems in some noteworthy wells and the solutions found for the Roncador field. The onsite experience is mandatory for successful applications, because modeling can not reproduce the large amount of variables.
New Findings in Fracture Cleanup Change Common Industry Perceptions
Authors: Ayoub J. A. , Hutchins R. D. , van der Bas F. , Cobianco S. , Emiliani C. N. , Glover M. D. , Kohler M. , Marino S. , Nitters G. , Norman W. D. , Turk G. A. 
Published: December 2007

Abstract
This paper summarizes part of the results of an investigation of fracture clean-up mechanisms undertaken under a Joint Industry Project active since the year 2002. It is well documented in the literature that hydraulic fractures, although successful, often underperform: Frac and Pack completions exhibit positive skin values, and traditional hydraulic fracture completions show discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited as a likely culprit.
The main results presented in this paper were obtained using a modified conductivity cell to allow polymer concentration via leakoff, and measurements of flow initiation gradients. The paper will discuss the experimental set-up and some of the artifacts that had to be removed prior to ensuring more reliable data. The results highlight the crucial role played by the filter cake and present new data that would significantly change the common industry practice of relying simply on an average polymer concentration factor.1-3
It is shown that contrary to the current method that calculates an average polymer concentration,the polymer,in practice, concentrates only in the filter cake. It is also shown that the filter cake thickness compared to the fracture thickness plays a critical role in creating significant yield stress effects,which could be either avoided through adequate design or used to estimate the resulting productivity loss.
What Would Be the Impact of Temporarily Fracturing Production Wells During Squeeze Treatments?
Authors: Al-Rabaani A. S. , Mackay E. J. 
Published: December 2007

Abstract
It is generally assumed that scale inhibitor squeeze treatments in production wells are displaced radially into the formation, since it is normal to pump these treatments below the fracture pressure. However, it is known that thermal stresses as a result of injecting cold fluids can result in thermally induced fractures (TIF). The first question that this paper addresses is the evidence of thermal fracturing during low volume (&lt;10,000 bbl) treatments, and then, secondly, what would be the impact on squeeze life of treating a well that was fractured during treatment vs a non-fractured well.
The process involves modelling of fractured and unfractured treatments to identify what are the advantages and disadvantages of temporarily fracturing a well during a squeeze treatment in terms of inhibitor placement. While inhibitor may be placed at a greater distance from the wellbore if the formation is fractured during the treatment, the surface area of rock contacted during the treatment may be less than is the case in radial displacements. Issues such as consolidated vs unconsolidated formations, initial reservoir temperature, fluid temperature at the sandface during injection, injection rate and fracture dimensions should be considered.
In general, this work demonstrates that there are clear advantages to temporarily fracturing a well during a squeeze treatment, depending on the inhibitor return concentrations required to prevent mineral scale formation.
Meeting Global Natural Gas Demand: The Emergence of Nigeria's LNG Industry
Authors: Igbatayo Samuel A. 
Published: December 2007

Abstract
A naturally occurring fossil fuel of light hydrocarbons, natural gas has become an important industrial input, propelling economic growth and development in both industrialized and developing countries. The global demand for natural gas has been accompanied by a booming business in the marketing of Liquefied Natural Gas (LNG), particularly in the last decade. Driven by the need to commercialize the nation's huge gas reserves, as well as the imperative to reduce its dependence on crude oil, the Federal Government decided in 1995 to revive the Nigeria LNG project, as a vehicle to facilitate the nation's entry into the global LNG market Nigeria LNG accomplished its first shipment of LNG cargoes to the world market in October 1999, ushering in a new era in the country's long-standing drive to diversify its export revenue.
. However, the actualization of LNG projects in Nigeria is not without challenges. Constraints include funding difficulties, particularly on the part of the Federal Government. Among other challenges, there is need for an enabling environment necessary to inspire investors’ confidence, a precondition for the attraction of crucial foreign investment into the industry. Therefore this paper provides a strategic policy framework promoting liberalization of the nation's gas industry. It also prescribes economic and administrative incentives needed to propel Nigeria's nascent LNG Industry towards a dynamic performance and to becoming a regional force in the global LNG market
Economics of Conditioning Nigerian Natural Gas for Market
Authors: Enyi Chimagwu G. , Appah D. 
Published: December 2007

Abstract
In a non-monopoly gas distribution system, each pipeline company has its own set of natural gas quality specifications to meet market requirement. The processing required and facilities employed depend on the nature of the field and composition of the natural gas.
The cost of conditioning a typical Nigerian natural gas for contaminations, in preparation for delivery to sales line was studies. This may vary in complexity from the simplest removal of water vapour to the most extensive removal of sulphur compound, non-combustible gases and many of the heavier hydrocarbons. The conditioning process consists of separation unit, carbon dioxide removal, and dehydration and dew point control units. The capital cost of procuring, installing, and operating these units were obtained using Nelson Farrar cost index.
It was observed that for a total capital investment of $12,382,590 for processing 10MMscf of the gas per day, and the cash flow of $39,417,300 for selling the processed gas at $1.55 per MMscf, an internal rate of return on investment (ROI) of 34.80% and a payback period (PBP) of 1.90 years were achieved. It is recommended that Government should encourage entrepreneurs in gas processing business, by providing good gas distribution pipeline networks to reduce operating cost.
New Opportunity Identification in a Mature Basin: The Oguta North Prospect in OML 20, Niger Delta
Authors: Esedo Ralf , Ozumba Berti 
Published: December 2007

Abstract
Prospectivity review of the northern part of OML 20 located in the oldest depobelt of the Niger Delta (Northern Delta depobelt) was carried out following the acquisition of 3D seismic data in this predominantly 2D covered area. The only giant field in the Northern Delta Depobelt is the Oguta field and was drilled based on 2D seismic data in 1965. Acquisition of 3D seismic data and its interpretation has changed the structural understanding in this part of the delta and has resulted in the identification of the Oguta North prospect, which is a large fault bounded hanging wall closure against a northwest to southeast trending fault block north of the Akri-Oguta field. The culmination of this prospect is against an oblique fault that could not be defined on the previously sub-optimally acquired old 2D.
The prospect is a material opportunity of about 15 km2, with a vertical closure of about 2000 ft. The objective interval ranges in age from Late Eocene to Early Oligocene when the delta was essentially lobate and presumably river dominated. At Oguta-Akri field to the south the objective interval is about 2000-3000ft with deposition in deltaic shoreface to shelf environments. These sediments vary northwards to more proximal environments at the Oguta North prospect. Reservoir thicknesses from the correlating intervals range from 30 –250 ft. The main risks associated with this prospect include lack of amplitude support in the main reservoirs, possible fault seal failure and the lateral extent of some of the reservoirs.
Establishing Actual Quantity of Sand Using an Ultrasonic Sand Detector; The Niger Delta Experience
Authors: Musa Lazarus A. , Temisanren Tuoyo , Appah Dulu 
Published: December 2007

Abstract
The quantity of sand produced has been determined using a Digital Signal Processing Ultrasonic sand detector. Conventional sampling methods alone do not give the true picture of sand produced in individual wells. On the other hand, operators have not been able to account for frequent de-sanding programs due to unnoticed sand being produced.
The major advantage of using the ultrasonic sand detector to detect sand is that sand monitoring has moved forward from a level of production trend to actual quantification in real time. The detector quantifies sand beyond its initial limit of profiling. The principle adopted uses an iterative method to locate a considerable threshold in the sand signature logged. Raw signals, in energy/sec, were simulated to reflect true sand production by marking up the background noise value, with about 10% to achieve the true sand free level of the signals for sand rate calculation.
This principle was applied to two fields in Western Niger Delta, comparing the sand results, in Ib/1000bbls, between conventional well head sampling results and ultrasonic detector results. Mostly 35 to 65, 37 to 63, 38 to 62, 43 to 57, 45 to 55 and 46 to 54 percentage distributions were obtained, and ultrasonic results proved to be even more reliable. A detailed comparison of both showed a considerable harmony in quality and quantity.
In this work, the unit of sand transportation, in gram per second measurement, was converted to pound per thousand-barrel (Ib/1000bbls) for oil and pound per million standard cubic feet (Ib/mmscf) for gas. These units simplified sand measurement using an ultrasonic device, when a conversion factor was introduced.
Permeability Prediction Using Genetic Unit Averages of Flow Zone Indicators (FZIs) and Neural Networks
Authors: Uguru C. I. , Onyeagoro U. O. , Lin J. , Okkerman J. , Sikiru I. O. 
Published: December 2007

Abstract
A significant improvement in the prediction of permeability from wireline logs has been achieved for the Niger Delta reservoirs using the concept of Flow Zone Indicators (developed by Amaefule et al) based on genetic unit classification as well as the application of neural networks. This concept is building on earlier reservoir description work whereby reservoirs in the Niger Delta have been classified according to the environment of deposition and by the lithofacies associations (i.e. genetic units) in these depositional environments. Using core data, averages of the FZIs have been computed for each genetic unit. FZI values have then been assigned to reservoir intervals without core data whose respective genetic units have been identified from log data using for example neural networks. The permeability values in the uncored reservoir intervals have thus been estimated using the permeability-FZI-porosity relationship for identified genetic unit in those wells or through multiple nonlinear regression using neural networks. Clear benefits of this improved estimation of permeability have been achieved in the process of history matching well behaviour in full field reservoir simulation models.
Simple Models for Some Fluid Thermodynamic Properties: Part I- Low Pressure Systems
Authors: Lawal Kazeem A. , Osunleke Ajiboye S. 
Published: December 2007

Abstract
Most mathematical models for estimating thermodynamic properties of fluids are complex, with their applications generally dependent on the operating range. This notwithstanding, the accuracy is rarely proportionate. Additionally, engineering needs often demand a simpler approach though with varying compromise of accuracy. This paper presents simple models for estimating some thermodynamic properties- compressibility factor, fugacity coefficient, molar volume, residual enthalpy and residual entropy, over well-defined and narrow range of pressure and temperature.
Employing the virial equation of state, a generalized but data-specific (local) model has been constructed for the compressibility factor of low-pressure systems. This model was then coupled with standard property equations to obtain data-based and boundary-respecting models for efficient computation of the other properties. Utilizing experimental data, with the objectives of computational efficiency, accuracy and local robustness, proposed models were constructed and compared with three existing, more rigorous models. The results were excellent. This notwithstanding, based on degrading performances observed, it is recommended that the
proposed models should be extrapolated with caution, if at all. This work is relevant to hydrocarbon production, processing and handling, facilities engineering and other field applications. These are in addition to unfolding new areas of research.
Framework for Sustainable Indigenous Technology Development and Capacity Building in Nigerian Petroleum Industry
Authors: Isehunwa Sunday O. , Falade Gabriel K. 
Published: December 2007

Abstract
A historical review of the evolution and development of engineering and technology generally in Nigeria is first presented. Major efforts at indigenous capacity building in the Nigerian oil industry did not commence until about 60 years after the first exploration efforts and ten years after oil discovery at Oloibiri. It was observed that in the last three decades, significant efforts have been made at establishing some institutions and infrastructure necessary for technology transfer and indigenous capacity building. Unfortunately, important requirements like favourable economic and political climate and essential linkages have been largely missing. A reliable survey and database of indigenous technology that can be applied in the oil industry is also missing. A general appraisal of the oil industry shows that while there is significant local expertise in Engineering services in such areas as drilling fluids engineering, PVT analysis, pipeline pigging and light facilities engineering, indigenous technological capacity is still very low and there is high dependence on foreign technology. We reiterate the well-known fact that ownership of production cannot be separated from the technology of production hence the need for a state-backed institutional framework for sustainable indigenous technology development and promotion of local content in the Nigerian oil industry as has been done in other counties and in the Nigerian defense industry.