bluuebunny/crossref_metadata_2025_split huggingface dataset:
First True Tight Gas (&lt;0.1 mD) Horizontal Multiple Fractured Well in the North Sea
Authors: Schrama Erik , Naughton-Rumbo Robin , van der Bas Fred , Norris Mark , Shaoul Josef 
Published: June 2011

Abstract
This paper describes the development of a tight gas reservoir in the Dutch sector of the Southern North Sea, using a horizontal well with 5 hydraulic fractures. The reservoir is tight (average permeability below 0.1 mD) and was discovered in 1986. The first development well was drilled as a long reach horizontal well in 1990, and completed with a cemented liner. The well was perforated and initial production was 0.2 mln Nm3/d after which the well quickly dropped below its liquid loading limit of 0.09 mln Nm3/d. The well was brought back into production 13 years later and produced at a stable rate of 0.07 mln Nm3/d. In 2005 the well was sidetracked using under-balanced drilling in an attempt to intersect natural fractures (Veeken, 2007). The initial production from this sidetrack was 0.1 mln Nm3/d, but this time the well was able to sustain production at 0.07 mln Nm3/d as the tubing head pressure was lower by that time.
To develop this reservoir, the well was sidetracked (overbalanced) in 2008 and completed with a cemented liner. In 2009, 5 hydraulic fractures were placed using a jackup support barge and a specially converted supply vessel. Since December 2009 the well has produced steadily at 0.3-0.4 mln Nm3/day, a (steady-state) production improvement factor of 5-6. This was the first true tight gas (&lt;0.1 mD) development in the North Sea using a horizontal well with multiple fractures. The initial production takes place at constant rate and constant pressure, which suggests that significant cleanup is taking place, either in the fracture or the reservoir or both. An attempt has been made to model this cleanup in a 3D reservoir simulation model.
This paper describes the background of the project, fracture design methodology, operational issues and lessons learned, fracture treatment data analysis, post fracturing production analysis (with over a year of production history) and production forecast. This paper is a valuable case study for operators and contractors involved in offshore fracturing operations in low permeability gas reservoirs.
Determination of Optimum Perforating Strategy in Tight HPHT Gas Reservoirs Based on Modified RP-19B Section 2 and 3 Tests
Authors: Atwood D. , Sultan N. , Humphreys A. , Grove B. , Langseth B. 
Published: June 2011

Abstract
Recent laboratory and field testing enabled Total Exploration and Production Norway (TEPN) to optimize the shaped charge design and gun system used for perforating an appraisal well test in the high pressure high temperature (HPHT) Victoria field, offshore Norway.
The laboratory testing consisted of two different phases; penetration tests under downhole conditions into stressed rock, and a temperature test to evaluate any degradation in shaped charge performance.
Test shots into stressed Nugget and Crab Orchard Sandstone rock targets were used to identify which of the four charge designs being proposed would provide the best downhole penetration performance. Charge D, a 28 gram, deep penetrating, high temperature charge designed for 3.50 inch gun systems, provided the deepest penetration into the stressed rock targets.
The temperature test subjected both the charges and gun system to the high end of the reservoir temperature for the worst case expected time required to run both guns and test string into the wellbore. Results indicated that the heated charges provided penetration performance into steel bars substantially matching unheated charge penetration.
This paper discusses a recommended test methodology to qualify perforators for high temperature wells, and the importance of conducting such a test program in close collaboration with field operations.
Novel Environmentally Friendly Fluids to Remove Carbonate Minerals from Deep Sandstone Formations
Authors: Mahmoud M. A , Nasr-El-Din H. A. , De Wolf C. A. 
Published: June 2011

Abstract
Carbonate minerals are present in sandstone formations. These minerals are either introduced to the formation during drilling/completion operations or naturally present in the rock. There is a need to remove these carbonates to enhance well performance. This especially true if there is a need to use HF-based fluids to prevent the precipitation of calcium and magnesium fluorides.
In this study, we introduced GLDA (L-glutamic acid-N,N-diaceticacid) a new environmentally friendly chelate to remove carbonate minerals from sandstone formations. We also compared its performance with available chelates like EDTA (ethylenediaminetetraaceticacid) and HEDTA (hydroxyethylenediaminetriaceticacid). Berea (5 wt% clays) and Bandera (11 wt% clays) sandstone cores were used in the coreflood experiments. The concentration of the chelates used was 0.6M at pH values of 11 and 4. The coreflood experiments were run at a flow rate of 5 cm3/min and 300°F.
Coreflood experiments showed that at high pH values (pH =11) GLDA, HEDTA, and EDTA were almost the same in increasing the permeability of both Berea and Bandera sandstone cores. GLDA, HEDTA, and EDTA were compatible with Bandera sandstone cores. The weight loss from the core was highest in case of HEDTA and lowest in case of GLDA at pH 11. At pH 4, 0.6M-GLDA performed better than 0.6M HEDTA in the coreflood experiments. The permeability ratio (final/initial) for Bandera sandstone cores was 2 in the case of GLDA and 1.2 in the case of HEDTA at pH of 4, and 300°F. At pH 11, HEDTA, EDTA, and GLDA almost were the same in enhancing the permeability of the Bandera sandstone cores. At pH value of 4, GLDA gave the best results in Berea and Bandera sandstone cores.
Viscoelastic Evaluation of a Surfactant Gel for Hydraulic Fracturing
Authors: Gomaa A. M. , Cawiezel K. E. , Gupta D. V. , Carman P. , Nasr-El-Din H. A. 
Published: June 2011

Abstract
A new viscoelastic surfactant-based fluid was developed as an alternative to conventional fracturing fluids. The surfactant gel structure can be formed by adding a combination of cationic and anionic surfactants to water. This technology enables a clean fluid that can be prepared in fresh water, brines, or even produced waters without requiring biocides. Also, the cationic surfactant in the system functions as a temporary clay control agent or KCl replacement. The objective of this study is to evaluate the proppant suspension ability of the system, and its dependence on total surfactant concentration (TSC), cationic/anionic surfactant ratio (C/A), and temperature.
Elastic and viscous properties (G’ and G") of twelve different formulae were measured using an oscillatory rheometer. Static and dynamic proppant settling tests were conducted at 2- to 4-ppg concentrations. Three proppant types were selected that had the same size, but different densities and shapes.
Based on the experimental results obtained, the apparent viscosity of the surfactant gel was found to be a strong function of the TSC and temperature, while it has a weak dependence on C/A ratio. The viscous regime increased with increasing temperature and increasing TSC, while the elastic regime increased only with increasing C/A ratio. C/A ratio was found to be the primary parameter that affects proppant suspension. Only the formulae that had C/A ratio higher than 1.5 and TSC greater than 30 gpt displayed good proppant suspension properties. For these systems, proppant shape didn't affect the settling velocity. The viscous regime region was not affected by increasing the breaker concentration, but the values of G’ and G" decreased with increasing breaker concentration. Viscosity reduction profile was affected greatly by temperature and TSC, but C/A ratio did not have any significant effect. Results obtained can be used to better design hydraulic fracturing treatments.
Bridging Particle Size Distribution in Drilling Fluid and Formation Damage
Authors: He Wenwu , Stephens Mike 
Published: June 2011

Abstract
It is commonly understood that a reservoir drilling fluid must be compatible with the reservoir rock, both chemically and physically. One important aspect in optimizing drilling fluid is distribution of bridging particle sizes. Appropriate particle sizes can limit fluid loss to the formation and minimize solid plugging into reservoir pores. Reservoir rocks have complicated fluid-flow systems and it is important to understand pore characteristics of the rocks including pore type, size distribution and connectivity; and, secondary changes such as dissolution and fracturing. If inter-particle pores are the dominant fluid-flow channels for the sandstone and pore distribution is relatively homogeneous, a full range of particle-size distribution of bridging material may effectively bridge all pore spaces. But for many types of sandstone, natural dissolution of feldspar, rock fragments, or carbonate material has created oversized pores. Appropriately sized particles should be used to bridge them, and smaller particles should be retained in fluids to bridge smaller pores and to improve filtercake quality. For carbonate rocks, fracturing and/or dissolution may have created large pores or fluid-flow channels. They are usually inhomogeneous in space. Their sizes vary greatly and could be up to centimeter scale. The bridging particle size distribution should be comparable to the inhomogeneous pores or channels, if practical.
Differential pressure between wellbore and formation pore fluid is also a factor which influences bridging size selection. At high differential pressure, relatively large particle sizes may help limit the solids plugging into pore spaces and decrease the effect of filtercake compaction. However, a combination of pore size, fluid property, and filtercake quality considerations are needed to achieve the most effective particle size distribution.
An Innovative Offshore Fracturing Campaign for a Mature Oil Field: Case Study Offshore West Africa
Authors: LeBlanc Gilles , Muryanto Bonifasius , Ducourneau Stephane 
Published: June 2011

Abstract
Many of the offshore oil reservoirs along the West African coast are maturing with substantial reserves still in place; solid technical and operational solutions are required to maximize their value. The field was initially developed in the late 1960's and has since been under water injection and gas lift. The reservoir is composed of laminated sand, silt, and shale sequences, all of varying reservoir quality.
As a result of the widely ranging permeability and poor vertical permeability, hydraulic fracturing was the technology chosen to unlock the remaining reserves. Operationally, "hard rock" hydraulic fracturing is not commonplace in offshore West Africa. Therefore, procuring the proper equipment, materials, and skilled personnel was the one of the biggest challenges. To alleviate the high cost of functioning with a drilling rig, an innovative rig-less setup was devised for a 9 well campaign.
The hydraulic fracturing method employed was conventional multi-zone fracturing using composite bridge plugs. Although very common in onshore, tight gas developments, the challenge was to properly apply it in an offshore project. Milling composite bridge plugs in under-pressured oil wells initially proved to be extremely challenging, while scale deposition made slickline well interventions very problematic.
The project has yielded numerous lessons learned and technical contributions:
▪ While the learning curve was steep, rigless "hard rock" fracturing techniques were successfully applied in offshore West Africa, thus being one of the few examples. This could have direct impacts on the future of the many offshore oil and gas fields. ▪ Consistent successful well interventions with slickline and coiled tubing proved to be the highest risk operation and often the root of most operational problems. ▪ The HSE risks using a floating barge and catenary coiled tubing system are key points which need to be considered when planning a rig-less fracturing campaign.
Effect of Residual Oil Saturation on the Propagation of Regular, Gelled, and In-Situ Gelled Acids inside Carbonate Formations
Authors: Gomaa Ahmed M. , Nasr-El-Din Hisham A. 
Published: June 2011

Abstract
In oil fields, serious difficulties with acid-induced sludge, a major source of well damage, can vary from a viscous, stable emulsion. A chemical analysis of sludge shows that hydrochloric acid (HCl) is present in the sludge structure. Also, Fe(III) ions in HCl formulations can cause a large amount of sludge. Even though ferric ion could not be detected in the oil phase or in the sludge, it induces sludge mainly because it works as a phase-transport catalyst for HCl. Therefore, the objective of this study is to determine the effect of residual oil saturation on the performance of regular, gelled, and in-situ gelled acids, that based on Fe(III) as crosslinker agent, inside the carbonate cores.
A core flood study was conducted using Indiana limestone cores (1.5" diameter & 6" long) at 200 °F. Propagation of the acid and crosslinker (Fe(III)) inside the long cores was examined. Analysis of the CT measurements was used to determine the locations of residual polymer inside the core. Acid injection rate was the main parameters that were investigated in this study.
Experimental results show that there was no compatibility problem between the used oil and the different acid systems. During injection of pre-flushed water, Pressure drop across the core initially increased because of creating oil bank in the zone behind the water. After reaching the maximum value, the pressure drops across the cores decreased by increasing the volume of water injection due to oil displacement. Increasing the injection rate during the pre-flush stage increases the amount of oil remained inside the core. At any injection rate, regular acid required more pore volume to breakthrough from the core that contains residual oil saturation. At 2.5 cm3/min, gelled acid took less volume to breakthrough from the core that contains residual oil saturation. However at injection rate of 10 cm3/min, gelled acid took higher volume to breakthrough from the core that contains residual oil saturation. At 2.5 cm3/min, damage due to gel was higher inside the core that contains residual oil saturation. However at injection rate of 10 cm3/min, damage due to gel was higher inside the core that contains residual oil saturation.
Investigation of Solids Flowback after Hydraulic Fracturing and Remedial Treatments
Authors: Agrawal Amit , Danait Achala , Nanda Jajati 
Published: June 2011

Abstract
One of the major concerns with hydraulic fracturing treatments has been the flowback of proppant and solids at various stages after the treatment. To mitigate this problem, it is necessary to understand the factors causing the proppant to flow back, which can help in the design of successful treatments.
This paper outlines the various analytical techniques used to identify the composition of solids recovered after performing a hydraulic fracturing job in the Middle East region. A laboratory test setup was designed to conduct tests by simulation of downhole conditions. Finally, a treatment was proposed to prevent flowback in future wells to be treated.
Analysis of recovered solids using X-ray diffraction (XRD), particle-size distribution, and high-resolution stereomicroscopy revealed the presence of formation sand, fibers, resin-coated proppant (RCP), non-RCP, and crushed proppant. Proppant flowback was observed in laboratory tests conducted using the same source of RCPs that was used for the job. The RCP packs exhibited poor consolidation after curing for 24 hr at 320°F. However, application of liquid-resin coating (LRC) to these RCPs resulted in well-consolidated proppant packs with high unconfined compressive strength (UCS). This in turn prevented proppant and formation-sand flowback when tested under simulated bottomhole conditions.
The results obtained further confirm the advantages of LRCs compared to conventional RCPs in hydraulic fracturing treatments.
Qualification of Scale Inhibitors for Conventional and Novel Scale Squeeze Applications to Deepwater Subsea Wells: Laboratory Testing to Field Application
Authors: Jordan Myles 
Published: June 2011

Abstract
Control of inorganic scale such as sulfate and carbonate has been possible via inhibitor chemical treatment or modification of the fluids types (i.e. desulfation of injection fluid). The deployment of scale inhibitor treatments via continual injection downhole and to topside process equipment is a common practice as it batch chemical treatments to production wells via the squeeze process.
The paper will outline the inhibitor selection process and field results for three oilfields (1) a conventional squeeze chemical selection study with coreflood and chemical placement evaluation for an application within two south American offshore fields and (2) non conventional batch chemical application for a West African offshore oilfield where scale inhibitor was applied within the fluids used to simulate the well prior to frac pack operation so providing initial scale inhibitor placement prior to initial water breakthrough. This non convention batch treatment eliminated a squeeze to these subsea wells and allowed uninterrupted production of oil until 850,000 bbls to 2,100,000 bbls of produced water was produced from the wells. The delay in applying the first squeeze to these wells allowed the water cut to increase above the relatively low water cut values (&lt;10% BS&W) associated with slow clean up post an aqueous squeeze treatment.
This paper will present with the aid of field data from both fields how the challenges of managing scale forced innovation in terms of when to apply scale inhibitor to deepwater subsea wells within the fields. The paper will demonstrate that scale management while being complex can be controlled and treatment programs optimised with the use of varied monitoring methods and the varied skill of the scale management team members.
Measurement of Breaker Requirements for Concentrated HPG Solutions
Authors: Gdanski Rick , Bryant Jason 
Published: June 2011

Abstract
Fracturing treatments in tight-gas sands often suffer disappointing production results. Conductivity damage caused by immobile gel filtercakes is often cited as a probable damage mechanism. Breaker requirements for reducing the viscosity of filtercakes remain a challenge, particularly at suspected filtercake concentrations of greater than 600 lbm/1,000 gal. Previous studies measured the rheology of non-crosslinked hydroxypropyl guar (HPG) across broad ranges of molecular weight (MW), temperature, concentration, and shear rate. The reported rheology model provided a means to experimentally evaluate breaker requirements to achieve a target uncrosslinked filtercake viscosity. Experiments were conducted to determine kinetics of polymer degradation by simple hydrolysis at temperature and degradation by sodium chlorite and sodium persulfate breakers. Temperatures ranged from 85 to 280°F, while breaker concentrations ranged from 0 to 80 lbm/1,000 gal. HPG concentration was held at 1 lbm/gal of 260 kg/mole HPG. The viscosity profiles during the experiments were matched with the rheology model to infer MW decline profiles and thereby determine the rate laws for reaction with the polymer.
It was found that efficiencies of breakers on breaking backbone linkages of HPG were only 2 to 5%, with the remaining breaker consumption apparently not reducing the molecular weight of the polymer. The rate laws for the breakers were found to be first order in breaker and first order in linkage concentration. The rate laws were used to make projections on the amount of breaker required to reduce concentrated gels to an arbitrary target viscosity.
Advanced Viscoelastic Surfactant Gels for High-Density Completion Brines
Authors: van Zanten Ryan , Ezzat Dodie 
Published: June 2011

Abstract
Viscoelastic surfactant (VES) systems are often used as viscosifiers for solids-free, high-viscosity pills used to control brine losses in production zones after perforation, gravel packing, or frac packs due to their non-damaging characteristics. Polymer gels have relatively higher rock retention values and often damage the invaded zone, so that acidization is required for removal. The VES systems behave as "equilibrium" or "living" polymers and their viscosity can be destroyed by contact with the produced hydrocarbons or with an internal breaker. This can eliminate the need for remedial treatments, greatly reducing operating cost/time and damage to the formation.
Historically, many VES systems have demonstrated limitations in high-density brines. Electrostatic screening generally reduces the viscosity or causes phase separation. Two methods have been found to stabilize VES packages in high-density completion brines: 1) by controlling the curvature of surfactant aggregates using low molecular weight surfactant polymers, nanometer scale manipulation of the phase behavior is achieved; and 2) VES gels have been developed using a mixture of oppositely charged surfactants to create gels in these high-density brines. By varying the ratios of surfactants it is possible to control micellar growth and the gel-like behavior. The interactions between the surfactants makes it possible to control the curvature and self-assembly on a nanometer scale, allowing the creation of polymer-like VES systems. The result is a greater variety of surfactants available to create gels in high-density completion brines.
This paper details the laboratory work performed to develop VES packages for fluids ranging from freshwater to high-density completion brines. Extensive rheology experiments on several fluids show the viscoelasticity of these systems. The self-breaking nature of VES systems when in contact with hydrocarbons or exposed to a built-in breaker has also been demonstrated.
Mixing Hydrochloric Acid and Seawater for Matrix Acidizing: Is It a Good Practice?
Authors: He J. , Mohamed I. M. , Nasr-El-Din H. A. 
Published: June 2011

Abstract
In offshore operations where seawater is commonly used to prepare hydrochloric acid, calcium sulfate precipitation, the potential of which can greatly reduce the effectiveness of these treatments. This is because high concentreation of calcium produced in spent acid mixed with high level of sulfate in seawater. However, a few studies have provided evidence for this problem and the effect of calcium sulfate precipitation on acid treatments has not been fully examined.
In this work, core flood experiments at 0.5, 1, and 5 cm3/min flow rates were performed at 25°C to investigate formation damage due to calcium sulfate precipitation during matrix acidizing treatment. Austin Chalk cores (6 in. length and 1.5 in. diameter) with a permeability of 10 md and synthetic seawater were used. The core permeability before and after acid treatment, pressure drop response, calcium ion, sulfate ion, and pH values in the core effluent samples were measured. Solids collected in the core effluent samples were analyzed using XPS technique. Both acid prepared in seawater and in deionized water were examined.
Results showed that calcium sulfate precipitation occurred when seawater was used in any stage during matrix acidizing including preflush, post-flush, or in the main stage. Injection rate was the most important parameter that affected calcium sulfate precipitation; permeability reduction was significant at low flow rates, while at high rates wormhole breakthrough reduced the severity of the problem. This work confirms the damaging effect of preparing hydrochloric acid using seawater for acid treatments.