bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application and Study of Fine-Silty Sand Control Technique for Unconsolidation Quaternary Sand Gas Reservoir, Sebei Qinghai
Authors: Zhou Fujian , Yang Xianyou , Xiong Chunming , Zhang Shouliang , Zong Yiping , Sun Lingyun , Guan Ziqiang 
Published: December 2007

Abstract
Sebei Gas Field is located in the northeast of Caidam Basin, Qinghai, China. Its main pay-zone is unconsolidation Quaternary fine-silty and dirty sandstones with serious sand production. Grain size of the sand is very fine, about 0.04-0.07mm, so sand control is very difficult. In past ten years, many sand control methods (such as mechanical, chemical and frac-pack sand control) have been applied; however, expectant effect had not been achieved. Condisering the conditions of Sebai Gas Field, we succeed in applying a series of technique of comprehensive sand control with fiber-resin coated sand. The technique adopts formation pretreatment, clear brine-based VES (viscoelastic surfactant) fracture fluid as sand carrier, special glass fibers and resin-coated sand complex for fracture pack stabilization and enhanced proppant transport, frac-pack and TSO (tip screen out) for increasing productivity, bypassing near well bore damage, interconnecting multiple sandstone layers and decreasing fluid velocities in the formation to reduce fines production. This combined rehabilitation technique enabled screenless sand control completion, allowing low cost rehabilitation of plugged or failed sand screens and the development of any numbers of gas layers which otherwise could not be drained with conventional sand control technologies.
The technique was exercised in well Se 3-18; the results proved to be remarkable. Before sand control, serious sand production begins at 4.5×104m3; after sand control, sand production cannot be found at 91200 m3/d. Up to now, the well has been produced for nearly one year with stable gas production at 10×104m3 and no more sand production. This paper presents lab study, operation design, field operation and result analysis about the sand control technique.
A Successful Scale Removal Operation by Use of New and Old Technology
Authors: Børeng Raymond , Skinnemoen Odd Kåre , Vigen Arild , Vikane Olav , Andrews Jamie , Larsen Ragnar , Hauptmann Thore 
Published: December 2007

Abstract
The Statfjord oil field, operated by Statoil in the North Sea, is far down its production decline curve. 60% of the STOOIP has been recovered during the past 23 years of production with secondary recovery techniques, leaving complex distributions of by-passed oil reserves, water and gas.
In order to maintain cost-effective production of the remaining reserves, an aggressive drilling and intervention programme is necessary. Future field development might also include a pressure blow down of the reservoir. So far the Statfjord Field has exhibited a fairly mild scale potential. Sulphate scale has been detected in several wells downhole; in the near well bore area, in the perforation tunnels or in the well bore. Well bore accumulation has been observed both as a thin layer along the tubing or as massive build up in the wire-line re-entry guide. Carbonate scale, when present, is mainly observed above the wireline retrievable downhole safety valve (DHSV). Statfjord wells are typically completed with wire-line retrievable downhole safety valves, which are function tested every 6 months. In wells prone to scaling this testing frequency is increased to 3-months.
In well C-36 scale build up had been confirmed in the 5 1/2" re-entry guide during production logging in June 1998. Following deterioration in well performance, a successful scale dissolver and inhibitor squeeze was performed early in 1999. Later in 2001 the DHSV failed, but this was corrected by an acid job. However, the safety valve failed again in June 2002 and proved this time to be immune to acid treatment and the well had to be shut in. The well condition was evaluated by running gauge rings into the well and this showed extensive scale build up over the DHSV. New and old technologies were evaluated for scale removal.
Statfjord has had good experience of scale removal with Coiled Tubing (CT) milling. This approach would probably have been successful in well C-36 but, due to long delivery time and the cost of deferred oil production, a wire-line solution was sought. An operation program was designed for mechanical removal of scale with wire-line (WL) broaches in combination with a stiff wire-line brush. Wire-line tractor (WLT) milling and string shots were included as back up options.
As the operation proceeded it became evident that mechanical broaching and backup WLT-milling were inefficient at removing the hard Ba/SrSO4 scale. However, use of explosives on string-shot runs was successful in removing the scale and getting the well back in production. In order to evaluate the scale removal process a multi finger caliper (MFC) was run several times during the operation. The MFC showed a scale layer with variable scale thickness up to a maximum of 1".
A successful scale-removing job was performed and the well came on stream with approximately 700-1000 Sm3/d of oil after the operation. A CT milling operation was avoided.
Application of New Fracturing Technique Improves Stimulation Success for Openhole Horizontal Completions
Authors: East Loyd , Willett Ron , Surjaatmadja Jim , McDaniel B. W. 
Published: December 2007

Proposal
A relatively new technique for applying fractures (both proppant fracs and acid fracs)1–3 in horizontal openhole and uncemented liner completions is giving operators a more effective method for stimulation of underachieving wells. The process incorporates the known technologies of hydrajetting and fracturing in a novel way to achieve individual fracture placement at several selected locations along the lateral without the need for mechanical isolation methods, usually with only one service trip to the location. Depending on the number of fracturing stages desired, most job times vary from 6 to 12 hr if there are no hole-entry, tool, or logistic problems.
Use of this new stimulation process continues to expand in the USA and Canada, and during the fourth quarter of 2002 and the first half of 2003, application of this process was successfully expanded beyond these original development areas to include offshore South America and a region of northern Asia. Before the end of 2003, numerous other locations around the globe are also planning to implement this stimulation technology on underperforming horizontal completions.
Although this stimulation technique can also be used for cemented liners, its unique ability to control fracture placement in openhole and uncemented liner applications will be the focus of this paper. Only a brief review the basic technology is presented here, as numerous earlier publications provide more detail. New case histories will be presented wherein the application of this process has provided the operator with a distinct improvement in well completion economics.
Fracture Treatment Design and Execution in Low Porosity Chalk Reservoirs
Authors: Cipolla C. L. , Hansen K. K. , Ginty W. R. 
Published: December 2007

Proposal
This paper details the results for 33 propped fracture treatments in low porosity zones in the South Arne field, Danish North Sea. To date, seven horizontal wells (2900 m TVD) have been completed using 100 tip screen-out (TSO) propped fracture treatments containing 70 million pounds of proppant. The target oil bearing Tor & Ekofisk intervals range from 40m to 120m of combined thickness, with a Young's modulus and permeability that can vary from less than 0.5 MMpsi to over 2.5 MMpsi and 0.1 to 4 mD, respectively, along the horizontal section. The wide variations in reservoir and rock properties presents significant fracture design and execution challanges.
Results indicate that propped fracture treatments become increasingly more difficult to place as porosity decreases and this problem is primarily attributed to higher natural fracture/fissure density in the lower porosity, higher modulus zones. Production data indicate that these natural fractures or fissures do not measurably contribute to productivity, but can be "activated" under fracturing conditions. Counter intuitive, pad size and fluid loss additives must be increased and maximum proppant concentration decreased in low porosity (low permeability) zones. In the higher porosity, higher permeability northern portion of the field, pad sizes of 35,000 gals containing 20,000 lbs of 100-mesh sand allowed the placement of 800,000 lbs of proppant at concentrations up to 15 ppa. However, in the lower porosity, lower permeability southern portion of the field, pad sizes of 200,000 gal containing over 100,000 lbs of 100-mesh sand were required to place similar proppant volumes, with concentrations limited to 8 ppa. This paper summarizes field data from 100 treatments, illustrating the design changes necessary to place propped fracture treatments in low porosity chalk reservoirs. The paper documents the relationship between chalk porosity, fluid efficiency, and treatment design.
Interpretation of Field Experiments and Observation of Fracturing Process
Authors: Daneshy Ali , Blümling Peter , Marschall Paul , Zuidema Piet 
Published: December 2007

Proposal
Detailed experiments were performed in four instrumented boreholes to determine the growth pattern of an induced hydraulic fracture and its impact on flow through an ultra low permeability formation. The instrumentation allowed measurement of fracture pressure and width in three boreholes which were intersected by a fracture induced from a central well. The fracturing fluid was synthetic pore water to prevent formation damage.
The experiments showed that because of the difference between the instantaneous fracture velocity and fluid velocity inside the fracture the fluid front lags behind fracture front. There was a large pressure drop along the length of the fracture which caused rapid narrowing of the fracture width, poor hydraulic communication along the fracture length, and localized growths and fluid movements.
The data confirmed an off-balance fracture growth pattern, consisting of tensile and shear fractures and many branches.
At the end of the treatment, even though the fracture contained some residual opening, it had very little conductivity along its length. At the same time, because of its off-balance growth the fracture had the capacity to transmit fluid locally and trap and hold part of the treatment fluid inside the ultra low permeability formation.
These experiments have raised new questions about some of our common assumptions in hydraulic fracturing. These include the pattern of fracture propagation, pressure distribution inside the fracture, fracture closure and re-opening, in-situ stress measurement, etc.
Radial Near Wellbore Stimulation by Acoustic Waves
Authors: van der Bas Fred , de Rouffignac Eric , Zuiderwijk Pedro , Wong Sau-Wai , van Batenburg Diederik , Birchak Bob , Yoo Kwang 
Published: December 2007

AbstractProduction of oil and gas wells is often reduced due to damage in the near-wellbore region related to the drilling process. In many instances, the damage is caused by the interaction of the reservoir formation with drilling and completion fluids. This damage can increase during the life-time of the well due to influx of formation damage (fines, scale, asphalthenes, etc). An example is formation fines plugging a slotted liner or screen.High frequency sonic waves have been used in many industrial applications to remove contaminants like dirt, oil, and grease from parts immersed in fluids. An obvious extension of this application is the removal of wellbore impairment by exposing it to high frequency acoustic waves. Although the concept is old, successful large-scale application of acoustic well stimulation is not yet common. During the last decade the manufacturing of high-power piezo-electrical elements developed fast and opened the potential to design a downhole acoustic cleaning tool.The advantages of an acoustic cleaning tool is the selectivity of the treatment compared with conventional matrix acidizing treatment. Also the need for large quantities of chemicals (acid, corrosion inhibitor etc.) can be eliminated.In previous publications the potential of acoustic cleaning has been reported using experimental results obtained in a laboratory set-up using linear acoustic waves. In this paper the results will be presented on the cleaning of mud damage using a prototype acoustic tool in a radial geometry.
Impact of Water-Based Polymer Fluid Characteristics on CO2 Foam Rheology
Authors: Fredd Christopher N. , Miller Matthew J. , Quintero Baudel W. 
Published: December 2007

Abstract
High performance foamed fracturing fluids are required to enhance cleanup during applications in low permeability, low pressure gas reservoirs and mature, depleted hydrocarbon reservoirs. Moreover, accurate foamed fluid rheological properties, obtained under field conditions, are necessary to enable complex fracturing treatments to be executed successfully. Standard laboratory tests used to evaluate properties of foamed fluids include the foam half-life measurement and the characterization of the water-based polymer fluid rheology that serves as the external aqueous phase of the foam. These tests are generally limited by the absence of CO2. In addition, the rheology tests are commonly performed with the pH of the water-based fluid adjusted with acid to a value consistent with that expected for CO2 foam under reservoir conditions.
This study evaluates the relevance of conventional laboratory tests in indicating the performance of CO2 foam fracturing fluids formulated with linear and zirconate crosslinked carboxymethylhydroxypropyl guar (CMHPG) polymer. Specifically, the effects of the water-based polymer fluid pH, crosslink delay and corresponding shear sensitivity, temperature, and foam quality are evaluated under typical conditions encountered in a fracture. Relatively new capabilities to measure pH in the presence on CO2 under high-pressure (up to 1,500 psig) and high-temperature (up to 280°F) indicate pH values in the range of 3.5 to 4.1 for CO2 foam under down hole conditions. Results demonstrate that the common practice of performing Model 50 rheology tests with water-based polymer fluids adjusted to low pH to simulate the effects of CO2 are not indicative of CO2 foam fluid performance, as the foam viscosity was not dependent on the crosslink delay or crosslink pH. Furthermore, standard shear history tests with zirconate-crosslinked CMHPG fluids did not correlate well with foam performance at qualities greater than 52% CO2. This work demonstrates the conditions under which CO2 foam rheology is dominated by foam properties versus water-based polymer fluid properties.
Optimizing Filtrate Design to Minimize In-Situ and Wellbore Damage to Water-Wet Reservoirs During Drill-In
Authors: Dalmazzone Christine , Audibert Annie , Quintero Lirio , Jones Tom , Dewattines Carine , Janssen Michel 
Published: December 2007

Abstract
A prominent area of concern related to drill-in and completion operations is damage caused by polymer and/or brine filtrate invasion into the producing formation. It is common knowledge within the petroleum industry that, in overbalanced conditions, filtrate invasion into the pore spaces of a reservoir is continuous as long as the drill-in fluid and wellbore are in contact. It is also commonly known that certain polymers and modified starch additives tend to adsorb or to be retained, and sometimes plug, the water-wet linings of reservoir pores. Once this occurs, flow paths are restricted and formation permeability is impaired. Despite the careful selection of less damaging polymeric viscosifiers and fluid loss agents, reduced mobility of production fluids remains a problem. Depending on the compatibility of the aqueous filtrate with the reservoir fluids, strong water/oil emulsions may be formed and also plug reservoir pores.
This paper presents credible laboratory data demonstrating the benefits of a special surfactant molecule engineered to pass through a drill-in fluid filter cake along with the other filtrate components to maximize wellbore productivity. Functionally, this chemistry (1) inhibits the adsorption of the drill-in and completion fluid polymers on the in-situ surface areas of the reservoir, (2) reduces the water saturation level of the formation rock to increase flow area, (3) promotes compatibility between the brine filtrate with formation crude, and (4) reduces the surface properties between filter cake particles to enhance the ease of wellbore clean up during displacement and natural cake "lift-off" during the onset of production.
Collectively, these benefits, when used to complement pre-established drill-in fluid design criteria, further increase reservoir productivity in open hole completion applications.
A New Industry Standard for Determining the pH in Oilfield Completion Brines
Authors: Prasek Bethicia B. , Freeman Michael A. , Carpenter Joel F. , Dalton Ferrill G. , Isaac D. Donald , Guy-Caffey Judith K. , Tomlin Marsha , Javora Paul , Jones Tom A. , Malachosky Ed 
Published: December 2007

Abstract
An API-sponsored work group has developed a robust field and laboratory method for determining the pH of oilfield completion brine. This method is precise, gives reliable pH values, is free from interferences, and can be easily implemented across industry. It is anticipated that this user-friendly method will be incorporated into the API Recommended Practice 13J: Testing of Heavy Brine.1
Viscosities for Completion Fluids at Temperature and Density
Authors: Ortego Anne M. , Vollmer Daniel P. 
Published: December 2007

Abstract
Brine viscosities are an important property in sand control and coil tubing operations. Viscosities are used to calculate sand settling rates for gravel packing and frictional pressure losses. Due to limited brine viscosity data, viscosites were determined for conventional completion fluids using an Oswald viscometer. Then three dimension equations were determined as a function of density and temperature for calcium chloride, calcium bromide, calcium chloride and calcium bromide, calcium bromide and zinc bromide, three salt mixture of calcium chloride, calcium bromide and zinc bromide, and sodium bromide solutions. All equations had an average deviation from the measured values of less than 10%.
Experimental and Theoretical Simulation of Gravel Pack Displacement in Extended Horizontal Offshore Wells
Authors: Martins A. L. , de Magalhães J. V. M. , Calderon A. , Mathis S. P. , Trujillo C. , Nguyen H. T. 
Published: December 2007

Abstract
This article presents the development of a computational tool to guide horizontal gravel pack design for long horizontal offshore wells. Mechanistic model formulation, experimentation at a large scale flow loop and software development are detailed. The computer simulation results are then compared with field data collected in Campos Basin operations, offshore Brazil. A discussion on design alternatives for long horizontal well at low frac gradient formations is presented. This discussion includes a sensibility analysis on screen eccentricity, open and closed BOP configurations and alpha vs alpha plus beta wave displacement options.
Completion of High-Rate Gas Wells, Horizontal Gravel Pack and Filter-Cake Cleanup: A Case History From the Mahogany Field, Trinidad
Authors: Akong S. , Tinegate I. , Hassanali H. , Tocalino S. , Omonze D. 
Published: December 2007

Abstract
Completing high-rate gas wells in areas where sand control is necessary ranks among the top challenges within the oil industry. High-velocity gas flowing through the downhole hardware combined with the abrasive nature of finer formation solids dislodged and produced can significantly shorten the completion life and have strong financial implications for the operator.
This paper describes the gravel-pack and filter-cake cleanup techniques applied to Mahogany MB-13, an offshore horizontal openhole completion and Trinidad's best producing well at the time of its production start-up. Optimizing these operations, along with correct well configuration and precise borehole placement in the reservoir structure, were fundamental to achieving high production rates.
The gravel placement method and the uniform coverage of the gravel-pack screens helped to deter the creation of high-velocity spots. This result allowed the operator to use higher drawdown pressure differentials without damaging the completion.
Aspects of the sand-control design, gravel-pack placement to ensure complete wellbore coverage, and the chemicals and procedures for filter-cake cleanup are analyzed in depth.
The new-generation sand-control service tools that were developed to preserve the optimum wellbore conditions from the end of drilling through the completion are also discussed.
Finally, production data from the MB-13 are presented to support the completion efficiency reported.
Improved Production with Mineralogy-Based Acid Designs
Authors: Jiang Zhizhuang , Luo Donghong , Deng Zhiyun , Chong King Kwee , Gdanski Rick 
Published: December 2007

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