bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Application of Foamers to Enhance Crude Oil Production
Authors: Debord Saet Byul , Lehrer Scott , Means Nancy , Crosby Simon 
Published: September 2011

Abstract
As a well ages, the reservoir pressure decreases and the liquid starts to accumulate at the bottomhole. Without reducing the hydrostatic head via deliquification technology, production would decrease more rapidly than the natural decline curve and would cease prematurely. In gas fields, foamers became emerging deliquification technology because they are relatively economic and flexible technology. Conventional foamers have been very successful for deliquifying brine-loaded wells to enhance gas production. However, there has been little success in treating oil-loaded wells with foamer due to the difficulties in foaming crude oil.
Novel chemistry that foams crude oil was identified, and new oil foamers were developed as a solution for oil-loaded wells. Two oil foamers were developed to handle different range of bottomhole temperature and application methods. The oil foamer performance was evaluated in a wide ranges of crude oils and water cuts to determine the type of liquid that the new oil foamers could treat cost-effectively. Lab evaluation of six oil samples showed that the new oil foamers effectively treated oils. Capillary tests determined the thermal stability limit of the foamers for down-hole injection. Sparge column tests assured that foam created by the oil foamers can be controlled with commercially available defoamers.
A field trial at a well in south Texas proved that the new oil foamer increases gas and oil production. Previously, this well produced intermittently due to low reservoir pressure. The lab tests determined the recommended dosage of the oil foamer and defoamer, and the dosage was optimized during the field trial. The oil foamer was applied continuously through a capillary tubing at a rate of 750 ppm after optimization. The defoamer was injected at the wellhead to control the foam issue at the surface equipment. The oil foamer application increased the days of production from 7 days to 12 days. Gas production was enhanced from 122 Mcf/D to 400 Mcf/D, and oil production increased from 13 BOPD to 100 BOPD. During the entire field trial, the defoamer successfully controlled the foam issue, and the foam did not pose any upset to surface equipment.
Shear Stability of EOR Polymers
Authors: Zaitoun A. , Makakou P. , Blin N. , Al-Maamari R. S. , Al-Hashmi A. R. , Abdel-Goad M. , Al-Sharji H. H. 
Published: September 2011

Abstract
An experimental study of shear stability of several high-molecular-weight polymers used as mobility control agents in EOR projects has been performed in well-controlled conditions. The shearing device was made of a capillary tube with ID of 125 μm, through which polymer solution was injected at controlled rate. The set-up enables a precise measurement of the shear rate to which the polymer macromolecule is submitted. The degradation rate was measured by the viscosity loss induced by the passage into the capillary tube. The shear rate was gradually increased up to 106 sec-1 while checking degradation rate at each stage.
Different commercial EOR polymer products were submitted to the test with polyacrylamide backbone and different substitution monomer groups. All macromolecules behave as flexible coils in solution. The parameters investigated were: Molecular weight (between 6 and 20x106)Nature of substitution group (Acrylate, ATBS/sulfonate, nVP/Vinyl-Pyrrolidone)Salinity
Polymer shear degradation increases with molecular weight and salinity, but decreases with the presence of Acrylate, ATBS and nVP. All results can be interpreted in terms of chain flexibility. The highly flexible polyacrylamide homopolymer is the most sensitive to shear degradation. Introduction of acrylate groups in the polymer chain induces some stability because of the rigidity provided by charge repulsion, which vanishes in the presence of high salinity (due to the screening of acrylate negative charges). ATBS and VP groups, which are larger in size, provide significant chain rigidity thus better shear stability. It is also shown that some very-high molecular-weight polymers, after passing the shearing device, attain a final viscosity lower than lower-molecular-weight products with the same chemical composition. This factor has to be taken into account in the final choice of a polymer for a given field application.
As a comparison, although less popular today than two decades ago, xanthan gum, which behaves like a semi-rigid rod, is shown to be much less sensitive to the shear degradation test than the coiled polyacrylamides.
New Steam Resilient Cement: Evaluation of Long-term Properties Under Extreme Conditions
Authors: Chougnet-Sirapian Alice , Pershikova Elena , Loiseau Anthony 
Published: September 2011

Abstract
There are more than 1200 heavy oil deposits worldwide containing approximately 13,000 billion bbls of oil. Various steam injection methods are used to mobilize the viscous fluid to flow so that it can be produced to surface. During the production process, the cement sheath maintaining wellbore zonal isolation is subjected to large mechanical strains imposed by temperature variations. Under these extreme conditions, mechanical and thermal cement properties are key factors to maintain wellbore integrity and to achieve the desired reservoir productivity. Significant heavy oil reserves are found in unconsolidated sandstone formations and carbonate formations. To avoid fracturing of these formations during cement placement, systems with densities below 1,800 kg/m3 are required. Further, during exposure to steam temperatures, formation type may affect cement structure and, hence, its material properties.
A new steam resistant cement system was designed to have tailored mechanical and thermal properties for slurry densities in the range of 1,400–1,700 kg/m3. To simulate the influence of formation composition on the material properties, cement samples were aged in autoclaves containing either water or water-saturated sand. Aging was continued up to six months at temperatures of 250-344 degC. A two-fold improvement of the material properties in the conditions simulating contact with the formation (water-saturated sand) is observed compared to standard curing conditions.
Cement sheath integrity is simulated for the new and conventional steam resistant cements for typical conditions of heavy oil wells, including the effect of the formation. The higher durability of the new cement material compared to conventional systems is confirmed. Operators can count on cement sheath integrity as they apply thermal processes to produce heavy oils.
Development of New Chemical Additive Detection Methods Inspired by the Life Sciences
Authors: Fuller Anne-Marie , Mackay Fiona , Mackenzie Cameron , Rowley-Williams Catherine , Perfect Emma 
Published: September 2011

Abstract
On first consideration it may not be immediately apparent that biological detection methods could be applied to oilfield fluid analysis; however there are strong analogies between the two. Like produced fluids, biological fluids such as blood are also complex multiphase liquids with solid components. Decades of research in healthcare has provided technologies which provide fast and accurate detection to ppm concentrations or below of a wealth of species present in bodily fluids. Many such techniques have been made simple and portable for home care formats. This paper will describe a range of detection techniques inspired by the life sciences being applied to the analysis of chemical additives in oilfield fluids, with particular focus on thermodynamic hydrate inhibitors and polymeric treatment chemicals.
Colourimetric detection reagents have been developed for the analysis of methanol and monoethylene glycol (MEG) in produced fluids and the method has been qualified with real fluids using inexpensive equipment that is simple to operate. Also, novel chemical tags have been tested for use with polymeric treatment chemicals, with highly selective detection being provided by complementary detection reagents. The results show precise and robust detection of methanol and MEG (down to 1 part per million (ppm)) in produced fluids and comparison with gas chromatography (GC) is discussed. Results of a chemical tagging study are also presented and discussed in terms of tagging strategies, simplicity of detection method (using inexpensive handheld equipment) and the detection sensitivity (down to parts per billion (ppb)) of the tags in the presence of oilfield fluids.
These methodologies demonstrate the promise of applying life science inspired technologies to the accurate, on-site measurement of chemicals which are difficult to detect using other, less simple methods. These technologies offer significant benefits to the production chemist due to the knowledge gleaned and the reduction in time to result.
Associative Polymer System Extends the Temperature Range of Surfactant Gel Frac Fluids
Authors: Gupta D. V. , Carman Paul S. 
Published: September 2011

Abstract
Early viscoelastic surfactant fluid systems provided a non-damaging, non-polymer viscous fluid option for many tight gas fracturing applications. These fluids were operationally simplistic with only a few additives. However, their rheological properties limit their use to about 140°F as a single fluid. For applications to about 250°F, foaming the fluids with CO2 or N2, usually 65 to 75 quality, can achieve stability with adequate viscosity, but this increases costs as well as operational and logistical complication. In addition, these fluids provide minimal friction reduction because at high shear they tend to behave more like water.
A new thickening system extends the temperature range of traditional viscoelastic surfactant (VES) fluids and provides additional downhole benefits. Based on a low-molecular-weight associative polymer, the thickener forms an associative gel with surfactants at elevated temperature. The polymer and surfactants can be considered environmentally preferred. The system uses only three or four additives, compared to nine or ten for conventional systems. The footprint for field operations is considerably reduced, as hydration units and chemical additive units are not necessary. In rheology testing, the system achieves a good structure with viscosity. The time required to gel with temperature can be accelerated or delayed chemically. Regain conductivity tests indicate performance is similar to that of VES fluids alone. The system also has beneficial traits for clay control, friction reduction, water-wetting and post-frac fluid recovery. If foamed, the system may provide stability at even higher temperatures. This paper will present the chemistry and results of laboratory testing of this new and unique fluid system. The system should have applications in areas requiring excellent regain conductivities, such as unconventional formations.
Mitigating Silicate Scale in Production Wells in an Oilfield in Alberta
Authors: Arensdorf Joseph , Kerr Scot , Miner Kirk , Ellis-Toddington Tyler 
Published: September 2011

Abstract
Alkaline surfactant polymer (ASP) floods in sandstone reservoirs are associated with silicate scaling of production wells. Many wells require numerous workovers and some must be abandoned. Mineral scale inhibitors are generally ineffective at treating silicate scale in these wells.
An oilfield in southern Alberta was placed under an ASP flood for enhanced oil recovery and subsequently experienced severe silicate scaling of production wells. The wells were under artificial lift with submersible progressing cavity pumps (PCPs). The silicate scaling resulted in numerous well workovers to replace the pumps and associated rods. Two new silicate scale inhibitors were developed and applied down hole to production wells via continuous injection.
The dose of chemical applied was approximately 250-500 ppm per well. The inhibitors decreased silicate scaling as evidenced by significantly increased run life of most wells. One well that required consecutive workovers after three and four months, respectively, was treated with inhibitor at 500 ppm and has subsequently produced without problems for more than 12 months. Similar results were seen with other wells. PCP torque has generally not increased, and, in some cases, has actually decreased with the scale treatment. In addition, coupons of treated wells have generally been clean, indicating that silicate scale is not depositing on metal surfaces.
Even though the inhibitors must be applied at several hundred ppm to mitigate silicate scaling, significant cost savings have been realized because of the reductions in well workovers and associated lost production. This paper will discuss the issues encountered at this oilfield and the resultant solutions and successful outcome.
Advanced Casing Design with Finite-Element Model of Effective Dogleg Severity, Radial Displacements and Bending Loads
Authors: McSpadden Albert R. , Coker Oliver D. , Ruan G. Colin 
Published: September 2011

Abstract
A purpose-built finite-element model (FEM) is applied to simulate radial displacement of a casing string constrained within an outer wellbore. The FEM represents a fully stiff-string model wherein the casing is approximated by general beam elements with 6 degrees of freedom at each node to account for all possible physical displacements and rotations. Results predicted include deflection of the casing centerline from the wellbore centerline, effective dogleg curvature, bending deformation, wall contact forces, and bending stress magnification.
In critical well casing design, accurate assumptions regarding bending stiffness may be necessary to avoid overly-conservative as well as non-conservative analysis. Challenging HPHT and extreme temperature wells are opportunities where increased design efficiency can be crucial. Alternatively, design for extreme loads such as overpull loads in long deviated wells may be non-conservative if severe bending stresses are not considered.
A realistic case study is presented which demonstrates the possibility to achieve cost efficiency by means of optimized casing design. Also a case study is presented where a non-conservative design may result if severe bending loads are not modeled. The purpose-built FEM code is in many ways preferable to use of commercial FEA packages because of the timeconsuming effort required to build up the detailed model.
In typical casing and tubular stress design, a "soft-string" model assumes casing strings are coincident with the wellbore centerline. The known or assumed wellbore curvature is applied directly to the casing string. Any effect of casing string stiffness and allowable radial displacement within the outer wellbore is ignored. In many cases this results in an overlyconservative analysis. Likewise the impact of bending stress magnification is typically ignored along with the effects of centralizer placement. This may also be non-conservative for critical overpull situations such as in ERD and horizontal wells.
Enyzmatic Synthesis of a Non Ionic Biosurfactant Derived from Ricinoleic Acid and D-glucose: Stability of its Surface Action Properties
Authors: de Medeiros Suzan I. , Souto Carlos R. , Fagundes Fabio P. , Costa Marta 
Published: September 2011

Abstract
Alkaline Bacillus subtilis protease catalyzed the synthesis of a biosurfactant derived from castor oil by esterification between ricinoleic acid and D-glucose in organic media using N,N- dimethylformamide as solvent. This mixture was kept under constant agitation at 60 °C. The conditions of enzymatic synthesis had been optimized before, with a maximum yield of 60% in 48 hours of D-glucose esters of long chain. Afterwards, the product obtained (Biosurfactant) was purified and characterized by different analytical techniques. This product reduced the water surface tension from 72 mN/m to 30 mN/m at room temperature and neutral pH. The purified biosurfactant was very stable over a broad range of pHs (2 – 12) and temperatures (25 – 100 °C). Besides, it showed a great solubility and stability in saline conditions (50 – 115 g/L). Aforementioned results suggest that D-glucose ester obtained can be efficiently used as a tensoactive agent, remaining stable under all conditions studied, thereby allowing its use as an emulsifier and/or lubricant in downstream processes of the petroleum industry, representing, therefore, a alternative for conventional surfactants.
Chemical Additives for Improving Compatibility of Drilling Fluid, Completion Fluid, and Other Well-Treatment Fluids for Deepwater Wells
Authors: Qiu Xiaoping (Victoria) , Morgenthaler Lee , Martch Eddy , Vu Hiep , Chtay Mootasem , David Vanessa Farrell 
Published: September 2011

Abstract
In deepwater completions in the GOM, synthetic-based mud (SBM) has been widely used for drilling the reservoir section. With increasing well depth and higher reservoir pressure, higher-density drilling fluids are used more and more often. It has been observed that with increasing density of drilling fluid, the incompatibility between drilling fluid, completion fluid, and other well-treatment fluids can cause more problems to drilling and completions. Consequently, the incompatibility can reduce the effectiveness of well completions and result in lower production. Often, the formation damage caused by the incompatibility can be very difficult to remediate.
We have identified incompatibility between drilling fluid, completion fluid, and other-well treatment fluids for many GOM wells in lab studies. Chemical additives were studied for preventing the incompatibility between drilling fluid, completion fluid, and other well-treatment fluids. Chemical additives selected from lab study have been applied to many GOM wells, and their use has resulted in improved well production and has prevented catastrophic damage to the wells. We developed proper lab test protocol to subjectively evaluate chemical additives that can prevent or minimize incompatibility between drilling fluid, completion fluid, and other well-treatment fluids. The application of the selected chemical additives on several GOM wells will be discussed.
This paper will summarize the lab test methods and lab test results based on testing for several GOM wells. It will also summarize the end results of well performance with the application of these chemicals.
ESP Recirculation System Solves Production Issue in Granite Wash Gas Well
Authors: Reid L. C. , Irish L. M. , Holland N. G. , Howard T. L. 
Published: September 2011

Abstract
A deep Granite Wash well was tested on an Electrical Submersible Pump (ESP) after being shut-in for 11 months due to uneconomic and unsatisfactory rod lift operations.
The three main objectives of the test were: (1) to determine if an ESP system can be successfully utilized on a gas well; (2) to implement a downhole recirculation system; and, (3) to monitor the economic impact of the installation of the ESP unit.
The challenges for the ESP system for this specific test included: (i) motor cooling restriction due to absence of adequate rathole; (ii) production from multiple perforations over 600 ft spread; (iii) low liquid flow (&lt;400 BPD); (iv) high gas-liquid ratio (&gt;1600 CF/BBL); (v) deep well depth (10,000 ft); (vi) small ID production casing (5.5" 17lb/ft); and, (vii) high potential wellbore scaling/corrosion issues.
Due to these challenges, using a traditional motor shroud jacket was considered a disadvantage. As a result, a downhole recirculation system was used as an alternative method to (a) prevent potential gas locking; (b) circulate fluid to keep the motor cool; and, (c) enhance capillary deployment of scale and corrosion chemical treatment.
This paper presents basic principles of the application of ESP systems in a gas well, principles of implementing a downhole recirculation system, and uncommon techniques to effectively operate an ESP unit in dewatering gas wells. It also includes the historical design challenges, system specific design/operation, and production results of the tested well.
The test concludes that it is possible to successfully and economically de-water a deep non-conventional gas well utilizing a properly designed ESP with a downhole recirculation system. In addition, the test had demonstrated the benefits of web-based monitoring of the variable speed controller and downhole sensor information.
Using Lines-of-Solutions to Understand Fracture Conductivity and Fracture Cleanup
Authors: Gdanski Rick , Fulton Dwight 
Published: September 2011

Abstract
Evaluation of fracturing treatments in tight-gas sands is often frustrated by uniqueness problems when matching gas rates and bottomhole flowing pressure (BHFP) data alone. A fit-for-purpose simulator was used to match gas rates, BHFP, cumulative water, and composition of the water during cleanup after a fracturing treatment.The simulator models physics of flow and chemical physics to provide improved history matching of the cleanup process. The well was cycled through several production and shut-in periods. Pressure transient analysis(PTA)was used along with a recently published line-of-solutions concept for evaluating the evolution of properties of the reservoir/fracture system.
History matching of the well-returns data with the fracture-cleanup model provided multiple solutions when matching gas, water, and BHFP. These solutions all fell on a "line-of-solutions" using a special plot of reservoir properties as a function of conductive length. In addition, a new line-of-solutions was discovered relating fracture conductivity as a function of conductive length. PTA of several buildups provided lines-of-solutions that evolved during the course of the cleanup. These tools demonstrated that the conductive length was roughly 100 ft, but apparently cleaned up to at least twice that over the next several weeks. The fracture conductivity was much lower than expected and was the cause of the disappointing productivity.
This work demonstrates that matching well-return compositionswith a fracture-cleanup model capable of chemical physics can lead to improved interpretations of both reservoir properties and fracture structure. The two lines-of-solutions provide a potentially powerful method of understanding the reservoir/fracture system
3D Hydraulic Fracture Simulation for Injection in Plastic Shales
Authors: El-Fayoumi A. , Zaki K. S. , Abou-Sayed A. S. 
Published: September 2011

Abstract
Injection and hydraulic fracturing in plastic shales can be a complex and problematic operation. Issues that accompany such treatments include shale swelling, plastic deformation, embedment’s and perforation tunnel stability issues. Simulators that model fluid or slurry injection in plastic shale have always overlooked the plasticity issues associated with these formations. The approach has led to erroneous estimation of fracture extent and dimensions. Post injection shale deformation due to pore pressure changes can also lead to detrimental effects on productivity (fracture closure due to creep) and well/casing failure.
The current paper offers clear quantitative insights into the overall effect of injection in plastic shales. The experience is gained through drill cutting injection operations that have been taking place in highly plastic shales in an environmentally sensitive remote location. Fracture and slurry containment have been investigated using state-of-the-art 3D fracture simulator to provide assessment of the injection and to estimate out-of zone growth as well as shale plastic deformations and the effects on fracture vertical growth at different batch volumes. Analysis of historical pressure trends and pressure fall-off tests confirmed results from the 3D Simulation and the injection history. The results provide insights that have implications on the job design and implementation of hydraulic fracturing in plastic shale gas, particularly the Haynesville.
The results from the 3D fracture simulator and pressure transient analysis combine to accurately assess fracture vertical and lateral extents in similar formations, hence, minimizing the risks associated with injection and fracturing in these highly plastic shales.