bluuebunny/crossref_metadata_2025_split huggingface dataset:
Environmentally Acceptable Polymeric Corrosion Inhibitors
Authors: Hellberg Per-Erik 
Published: September 2011

Abstract
This paper will introduce newly developed polymeric corrosion inhibitors intended primarily for use within the oil- and gas production application area. Some of the products fulfill British and Norwegian environmental criteria for off-shore use, which are considered to be the most stringent in the world. In this paper the products are characterized with respect to e.g. static and dynamic surface tension as well as critical micelle concentration. Further, surface adsorption characteristics on different relevant surfaces using QCM-D (Quartz Chrystal Microbalance with Dissipation) are presented and correlated with the results of standard oilfield corrosion inhibition tests such as two-phase static bubble tests and RCE tests. In the paper possibly unique flow sequences with different oilfield-relevant liquids using the QCM-D equipment to assess the adsorbed layer persistance under various conditions are presented.
Additionally the polymeric surfactants in all aspects detailed above are compared with standard monomeric oilfield corrosion inhibitors having related chemistry. Finally, environmental test data of the new products according to North Sea regulations are discussed.
Challenges and Opportunities Heavy Oil Development Offshore UK
Authors: Berg Eirik A 
Published: September 2011

Abstract
This paper discusses the most important field development challenges of Mariner and Bressay with focus on subsurface related issues on Bressay. The fields have 11-14 o API oil. The reservoir viscosity is from 65 cp to 540 cp. No other offshore fields have yet been developed with 540 cp oil viscosity or more. Challenges include achieving high oil rate and recovery. Unconsolidated sand means limited availability of high quality exploration data and limitation to production well design. Lack of seismic resolution between the sands and shales limits the mapping potential in some of the reservoirs. Old well data means lack of high quality data. Significance of relative permeability and PVT uncertainties has been assessed and a reduced uncertainty span has been suggested by reinterpreting old data in combination with new laboratory experiments. Cuttings and log data is used primarly to establish permability distribution. Reservoir development strategy has been significantly revised compared to the previous Operator. The Mariner and Bressay field development sanction work is ongoing. This includes an updated flow assurance strategy using diluent to reduced challenges relegated to production and processing of heavy oil.
Improvements to Hydrophobically Modified Water-Soluble Polymer Technology to Extend the Range of Oilfield Applications
Authors: Eoff Larry 
Published: September 2011

Abstract
Hydrophobically modified water-soluble polymers have unique associative and adsorption properties that make them attractive for oilfield use. Previous publications have outlined the use or potential use of these materials for water reduction in producing wells, fluid diversion, leakoff control, brine viscosification, stimulation treatments (fracturing and acidizing), and enhanced oil recovery (EOR) applications. The commercial success of a hydrophobically modified polymer based on a C16 modified acrylate in such applications has been well documented. A brief summary of case histories for each of these operations is presented.
While this class of polymer has shown a wide variety of commercial uses to date, its full potential remains unrealized because of its low critical solution temperature (LCST) (&lt;160°F). This is the temperature at which the polymer precipitates, especially in high-pH fluids, such as those used in borate-crosslinked fracturing gels. The LCST values vary inversely with the pH of the fluid containing the polymer. While this temperature-limitation problem can be partially mitigated by using pH-control agents, it was desired to develop systems that do not suffer from this limitation and allow for extension of the use of such polymers in a variety of wellbore-treatment fluids and well conditions. This paper describes laboratory results from a two-pronged approach to overcome this limitation—(1) synthesis of alternate polymers that would retain the performance characteristics of the original polymer without its limitations and (2) chemical alteration of the formulations containing the original polymer to eliminate the LCST/pH limitation. Laboratory-testing data will include LCST dependence on pH for different polymers, fluid compositions, as well as core-flow comparisons. Ultimately, a simple yet effective chemical solution that not only maintains the performance of the original polymer but also potentially expands the area of usefulness was found.
Permeability Change during CO2 injection in Carbonate Rock: A Coreflood Study
Authors: Mohamed I. M. , He J. , Nasr-El-Din H. A. 
Published: September 2011

Abstract
Carbon capture and storage (CCS) has been proposed to mitigate the accumulation of the CO2 in the atmosphere. Although CO2 is captured from large point source and stored in underground formations (depleted oil reservoir, water aquifer, and salt cavern) as a mitigation of global warming, CO2 has been injected for various purposes like in enhanced oil recovery (EOR), and enhanced coal bed methane (ECBM) recovery. Water alternating gas (WAG) technique is used to inject CO2 into underground formation either in sequestration or in EOR. Injected CO2 dissolves into the water, generating carbonic acid which dissolves carbonate rock.
The composition of the water is a critical factor that affects the rock dissolution and the formation permeability change during sequestration, especially while using sea water that contains sodium sulfate. This paper addresses the effect of brine salinity and salt type on the formation during sequestration.
A core flood study was conducted using limestone cores. The CO2 was injected under supercritical conditions. Core effluent samples were collected and concentrations of calcium and magnesium, and sodium were measured. Cores permeability was measured before and after the experiment.
The results showed that no change in permeability noted when NaCl brine was injected. Calcium chloride has the main effect in calcium dissolution and change in core permeability. Also, increasing the concentration of magnesium chloride caused more damage to the core. The experimental data was used to develop an empirical correlation to calculate the maximum calcium concentration in the core effluent, which gives good indications on various reactions that might occur inside the core.
An Assessment of Completion Efficiency Comparing Actual Production Results to NMR Predicted Rates in the Rocky and Ammunition Fields - Oklahoma
Authors: Brinska John , Smith Charles H , Bray Jim , Ramakrishna Sandeep , Menendez Eli 
Published: September 2011

Abstract
These two fields in Washita County, Oklahoma present extensive traditional log interpretation problems. The wells contain a variety of sandstone reservoirs, including Britt, Boatwright, Cunningham and Schneberger. Each provides unique log interpretation issues. A clear definition of log derived porosity is extremely difficult for these reservoirs in the best of circumstances. Permeability is also an issue. Well to well correlations are unreliable due to the variability within the formations. In many cases, the expectation for the performance of the well was subject to little science and much conjecture.
In order to arrive at effective porosity and an estimate of permeability, NMR logs were added to the traditional logging program. At the time of logging, the technique employed for analysis of this log relied heavily on work done in the area. Parameters for analysis of a specific reservoir in a specific area were held constant with raw measurements of the tool considered to make changes to the base model. The Bray-Smith permeability model was applied to present estimates of permeability utilizing only the data generated by the NMR device.
This paper attempts to compare the results of this new permeability measurement technique with the production actually observed from this field. We will compare and contrast the results of three methods of developing permeability from NMR measurements. These will all be compared to the actual results achieved in the wells in the Rocky and Ammunition fields in Western Oklahoma.
Experimental Study of Spreading and Wettability Effects by Surfactants in Condensate Reservoirs at Reservoir Conditions
Authors: Zheng Y. , Rao D. N. 
Published: September 2011

Abstract
Gas condensate reservoirs suffer a rapid decline in productivity as the flowing bottom-hole pressure falls below the dew point. This reduction is caused by condensate accumulation near the wellbore. This study aims to perform an experimental investigation into potential remedies through chemical treatments to modify the fluid-fluid spreading coefficient and wettability in condensate buildup regions to enhance condensate recovery and gas productivity.
In this study, experiments were conducted at reservoir conditions of 2264 psia and 210 °F by using representative condensate reservoir fluids. Spreading coefficients were determined through measurements of oil-water, water-gas and gas-oil interfacial tensions using the Drop Shape Analysis (DSA) and capillary rise techniques. Dynamic contact angles were measured using the Dual-Drop-Dual-Crystal (DDDC) technique to characterize reservoir wettability. An advancing angle of 153° obtained from the experiments indicated that this representative sandstone condensate reservoir had a strongly oil-wet nature at reservoir conditions.
In order to examine the capability of certain chemicals to alter spreading and wettability behavior at reservoir conditions, an anionic surfactant was screened for use in the experiments at the concentration levels of 500, 1500, and 3000 ppm. Although spreading coefficients were all positive for the gas-condensate-brine (with and without surfactants) systems, a decreasing trend was observed in the systems after the surfactant application. This indicates that condensate recovery is still enhanced from surfactants usage in this strongly oil-wet system. The low concentration 500 ppm of anionic surfactant was not found to change this sandstone reservoir wettability at reservoir conditions, however, the wettability alteration from strongly oil-wet to weakly oil-wet or intermediate-wet was observed as the surfactant concentrations increased to 1500 and 3000 ppm. This study thus demonstrates the potential for surfactant-induced wettability alteration and spreading coefficient reduction in resolving condensate blockage problems.
Use of the NMR and Resistivity Logs to Quantify Movable Hydrocarbon; Solution for the Tight and Low-Resistivity Carbonate Reservoirs
Authors: Mohammadlou M. H. , Langeland H. , Mørk M. B. 
Published: September 2011

Abstract
Until an accurate fluid saturation tool is designed, the lack of a solid link between the petrophysical properties of reservoir rock and fluid is a real problem. The reservoir water saturation models are normally based on the standard Archie model to calculate fluid volumes. However, in tight carbonate reservoirs with heterogeneous wettability this model may present unrealistic results for the fluid volume (e.g., water/oil/gas) estimates. An integrated model using resistivity and NMR logs is introduced to quantify the movability of hydrocarbons in the reservoir transition zone. Pay zones may be missed in low-resistivity reservoirs (i.e., transition zones) due to the high water volume estimated from conventional logs.
New synthetic resistivity logs are made in both the invaded and non-invaded zones based on assumptions made on the basis of pore and fluid interaction in the NMR log T2 distribution. The differences between the original and synthetic resistivity logs in connection with other log data are dominant signatures of the fluid volumes and movability in the formation. The new approach is developed on basis of exploration well data from a complex and heterogeneous carbonate reservoir in the Norwegian Barents Sea. The estimated fluid movability results are in agreement with the wireline formation tester (WFT) measurements of the well.
This model, in addition to the transition zone, can also be applied for hydrocarbon bearing intervals which contain connate water. This approach shows that the reservoir wettability signature can also be identified by comparing the measured and constructed resistivity logs.
Practical Method for Measurement of Injection-gas Throughput of Each Gas-Lift Valve before Well Installation
Authors: Shahri Mehdi A. , Winkler Herald W. 
Published: September 2011

Abstract
The tester set initial opening pressure of a gas-lift valve (GLV) and port size are no indication of its injection-gas passage at a given injection-gas pressure for unloading and/or gas lifting a well. The initial test rack opening pressure (Ptro) of a GLV creates an opening force that slightly exceeds the valve’s closing force. The importance of the required injection-gas throughput performance of a GLV for unloading and gas lifting a well increases for very high daily liquid production rate wells and for wells that the workovers are very costly.
A test procedure that allows individual injection-gas throughput rate testing of every GLV and check valve prior to being installed in a well is described in this paper. The method includes GLVs with cross-over seats that prevent stem travel probe test measurements. The test requires very little gas volume and is based on a rapid pressure decline (blow-down).
Recent computer electronics as National Instruments LabVIEW software and 4 channel data acquisition instrument control hardware can record up to 12,500 pressure readings per second per channel. Test procedures are now possible to dynamically test the gas throughput performance of a GLV in a fraction of a second.
GLV replacement can be very costly – even by wireline in wells with subsea wellheads. After setting the Ptro and aging (stabilizing) this set opening pressure, the dynamic blow-down test can be performed on each GLV with check valve. If the GLV passes this test, the valve will have the injection-gas throughput required to unload and/or gas lift the well. Every supplier of gas-lift valves should offer this testing option to the producer.
Environmentally-acceptable Replacement of 2-Butoxyethanol: A High Performance Alternative for Fracturing Applications
Authors: Wylde Jonathan J. , O’Neil Bill 
Published: September 2011

Abstract
This paper concerns the development and implementation of a replacement chemistry for 2-butoxyethanol used in fracturing. The new product was synthesized to provide mutual solvency, wettability modification and clay swelling inhibition.
Recently, 2-butoxyethanol has come under scrutiny in North America (e.g. prompting Environment and Health Canada to add it to Schedule 1 of the Canadian Environmental Protection Act). Precautions need to be taken when working with 2-butoxyethanol due to toxicity concerns. Exposure to high levels has led to reported nose and eye irritation, headaches and vomiting.
Introduction of an alternate product has had a profound effect on the stimulation market in Canada. So far, 400,000 kg of the alternative product has replaced an estimated annual usage total of 3 to 4 million kg of 2- butoxyethanol. The new product also has had successful applications in the US, Latin America and Europe. There has been a significant environmental impact already realized through the use of this alternative product, and there is even greater unrealized potential. Additionally, as a non-regulated product for use and handling, the safety and material handling implications are greatly improved.
This paper details the chemistry of the replacement product, as well as environmental information to support the use of this product as a benign replacement for 2-butoxyethanol. An in-depth description of the laboratory testing used to identify, evaluate and select the appropriate treatment parameters also is given. The paper concludes with two case histories from northeast Alberta where this product was successfully used as part of a fracture treatment for long, horizontal, multi-zone shale gas plays. Furthermore comparisons are made using 2-butoxyethanol and no mutual solvent chemistry in a fracture treatment. This data shows the clear benefit of using this new chemistry.
Evaluation of Scale Inhibitors in Marcellus Waters Containing High Levels of Dissolved Iron
Authors: Shen Dong , Shcolnik David , Perkins Randall , Taylor Grahame , Brown J. Mike 
Published: September 2011

Abstract
The Marcellus waters of Pennsylvania and West Virginia commonly contain elevated levels of calcium, barium, and iron. Theoretical analyses of these waters indicate a propensity toward the formation of calcium carbonate, barium sulfate, strontium sulfate, and iron-related scales. The high level of dissolved iron commonly present in the water adversely affects the ability of the scale inhibitor to inhibit calcium carbonate scale. In this study, the inhibition performance of two new chemicals and some commercial products was evaluated under static and dynamic test conditions using synthetic Marcellus waters at varying iron concentrations. It was shown that both new chemicals were able to control calcium carbonate scale effectively in the presence of dissolved iron up to 200 ppm, whereas the performance of Polycarboxylic acid, Amino Tri(methylene phosphonic) acid and Carboxymethyl Inulin dropped sharply even in the presence of small amounts of Fe2+ (5 ppm). The inclusion of iron sequestering agents with these chemicals and the effect of iron upon calcium sulfate inhibition were also discussed in this paper.
Rheology and Stability of Non-Aqueous Micro Bubble Based Drilling Fluids
Authors: Shivhare S. , Kuru E. 
Published: September 2011

Abstract
The micro bubble (colloidal gas aphron) based drilling fluids have the unique pore blocking ability which helps reducing the drilling fluid invasion into the reservoir. The effects of time, temperature and pressure on the size and stability of the microbubbles need to be better understood in order to design a fluid that will have minimum filtration loss into high permeability zones.
A non-aqueous micro bubble based drilling fluid was formulated by using mineral oil (light paraffin oil composed mainly of alkanes and cyclic paraffins) as a base fluid, an oil soluble polymer (Styrene Ethylene/ Propylene Linear copolymer) and a non-ionic oil-soluble surfactant (Sorbitan Fatty Acid Ester). The effect of polymer and surfactant concentration on the aphronized drilling fluid characteristics was studied earlier to formulate an optimum drilling fluid composition.
In this study, effects of temperature and pressure on the rheology, filtration loss characteristics, and the stability of non- aqueous micro bubble based drilling fluids were investigated. PVT analysis was also conducted to develop an equation of state for non-aqueous micro bubble based drilling fluids.
Treatment of Mercaptans in Canadian Condensate
Authors: Arensdorf Joseph , Horaska Darin 
Published: September 2011

Abstract
Mercaptans occur naturally in sour crude and condensate and cause an unpleasant odor which is a nuisance to operators and surrounding communities. Regulatory authorities often require control of mercaptan odors.
A facility in Alberta stores condensate for use as a bitumen diluent. The condensate, which is stored in a large 110,000 barrel (bbl) (17,500 m3) holding tank, typically contains 150 to 400 ppm of total mercaptans (as sulfur). The odor resulting from these mercaptans can be detected off-site and is a nuisance to neighboring facilities.
Acrolein was selected as a sulfide scavenger to reduce the mercaptan level in the condensate. At the time of treatment, the condensate had a total mercaptan level of 224 ppm. Impellers in the tank were started to mix the condensate, and then 9,260 liters of acrolein were injected into the bottom of the tank while mixing. This amount of acrolein was calculated to achieve a 50% reduction in total mercaptan content.
The total mercaptan level in the condensate was actually reduced by 59%, from 224 ppm to 91 ppm (133 ppm scavenged). Acrolein scavenges all mercaptans, but preferentially reacts with the lighter mercaptans first. Ethyl and propyl mercaptan were reduced 88% and 53%, respectively. These light mercaptans were the most volatile and worst smelling mercaptans present, so their selective removal made the treatment efficient for odor reduction. Mercaptan odor was not detected at the site during the application even though the tanks were being stirred. After the application, mercaptan odors were significantly reduced and not detectable off-site.
The condensate was not adversely impacted by the treatment and was able to be transported by pipeline for use in processing bitumen. This application demonstrates that condensate containing problematic levels of mercaptans can be successfully treated using acrolein, and subsequently be safely transported and used as a bitumen diluent.
The Bottom-Line of Horizontal Well Production Decline in the Barnett Shale
Authors: Fan Li , Luo Fang , Lindsay Garrett , Thompson John , Robinson John 
Published: September 2011

Abstract
During the last five years, many shale gas plays have emerged, such as the Woodford, Haynesville, Fayetteville, Marcellus, Eagle Ford, etc. However, the Barnett Shale is the most mature of the currently producing gas shale plays in the US. Understanding the production mechanism and the production decline characteristics of the Barnett Shale will contribute to a better understanding of how newer shale plays will behave in a longer term. A production decline curve analysis (DCA) in the Barnett Shale is presented that incorporates public production data from over 8,700 horizontal wells. This analysis is performed by grouping wells based on years on production. Production data are normalized to zero-time, and regression history-matching is performed to estimate decline curve parameters. Long-term production is forecasted for 30 years. Production decline results strongly suggest hyperbolic decline. Particularly, the b value ranges from 1.3 to 1.6. First-year decline rate ranges from 56% to 74%. Thirty-year cumulative production ranges from 2.0 to 3.0 Bscf. The Best 12-month average gas rate and first 24-month cumulative gas production show a consistent trend and correlate very well with the predicted 30-year cumulative gas production. In spite of the advancement in completion and drilling practices, the gas recovery from newer wells is slightly worse than that of the older wells. This may be attributed to the poorer reservoir quality outside the core area or interference between wells due to down-spacing. Wells producing more than 5 years are often restimulated using hydraulic fracturing techniques. It is still too early to tell the impact of re-stimulation on ultimate gas recovery. However, the re-stimulated wells all show an increase in the short-term well productivity.