bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Downhole Oil/Water Separation in a Casing
Authors: Svedeman S. J. , Brady J. L. 
Published: June 2014

Abstract
Laboratory tests were conducted to evaluate the effectiveness of oil/water separation in a deviated well casing that is located below the perforation intervals.
Downhole water separation and reinjection is needed to reduce well operating costs associated with producing large amounts of water to the surface. In the casing separator, produced water flows downward from the well perforations with entrained oil buoyantly separated to the topside of the casing. A dip tube, running to the bottom of the casing, feeds a downhole pump that pumps the water into another level in the reservoir.
A test facility was constructed to test the casing separator performance at a variety of well inclination angles, production flow rates, water cuts, and reinjection water flow rates. At each operating condition, the amount of oil entrained in the reinjection water was measured to determine the maximum amount of water that could be separated and still provide "clean" water to the downhole pump. Tests were conducted over well inclination angles from 18° to 75°. The maximum water velocity in the casing separator, for clean water, varied from 0.2 ft/sec to 0.4 ft/sec.
The test results provided the information needed to determine how much water could be separated in the casing separator.
With the separator performance data, the economics of reinjecting water with a downhole pump could be evaluated.
A Modern Approach to Optimizing Underground Natural Gas Storage
Authors: Economides Michael J. , Wang Xiuli 
Published: June 2014

Abstract
Natural gas will emerge as the premier fuel of the world economy for two primary reasons: a surfeit of new and massive discoveries and substantial environmental benefits. Because of new and proliferating modes of transportation, natural gas will become fungible. This is likely to reduce large seasonal price fluctuations and especially it will eliminate price disparities, currently observed throughout the world.
Natural gas underground storage, mostly a North American practice, using depleted oil/gas reservoirs, water aquifers, or salt domes, will have to be expanded and enlisted almost everywhere.
We present here a series of new models for the physical management of gas storage facilities and the indicated injection and withdrawal schedules. Connected to the physical models are economic models that take into account natural gas price fluctuations. Optimum injection and/or withdrawal rates are determined weekly.
The model implementation starts at any time in the life of a storage reservoir with any amount of gas in storage. Then, taking into account gas price fluctuations, an injection/withdrawal schedule is determined to maximize profit and eliminate loss. The possible natural gas rates are not arbitrary but will be related to average rates already experienced in the field that are based on material balance, reservoir pressure and at the extremes, the abandonment pressure and the maximum allowable injection pressure.
We apply the models to entire US storage industry for two significant years, 2008 and 2012, compare and critique actual past injection and withdrawal history with the would-be optimum injection and withdrawal schedule that should be based upon gas price history. We show the disparity between the optimum schedules and what was actually followed. We also show considerable improvement in storage economics, compared to the actual history, if only the previous weekly prices were to be used as the gauge for injection/withdrawal.
Connate Water Saturation - Irreducible or Not: the Key to Reliable Hydraulic Rock Typing in Reservoirs Straddling Multiple Capillary Windows
Authors: Xu Chicheng , Torres-Verdín Carlos , Yang Qinshan , Diniz-Ferreira Elton Luiz 
Published: June 2014

Abstract
Irreducible water saturation is an important attribute to quantify reservoir petrophysical quality in terms of flow capacity. High in-situ capillary pressure causes connate water saturation in reservoir rocks to approach the irreducible stage, thereby providing a direct link between electrical and hydraulic conductivities. A new hydraulic rock typing method is developed by relating resistivity-saturation equations with core-calibrated Timur-Tixier's permeability model, both of which are expressions of porosity and irreducible water saturation in this special reservoir context. Petrophysical quantities equivalent to Leverett's reservoir quality index (RQI) and Amaefule's flow zone indicator (FZI) are derived from petrophysical analysis based solely on conventional logs, including gamma ray, neutron porosity, bulk density, and resistivity.
We test the new method on a deltaic gas reservoir from offshore Trinidad (Columbus Basin). In the field case, rock typing accuracy based on the new rock typing method is improved by 12% in terms of their contingency coefficients with core-based hydraulic rock types. We also discuss the limitations of the new method in detecting and ranking reservoir rock types in complex contexts of reservoir saturation-height. A new concept, referred to as capillary window, is developed to categorize the applicability of the new rock typing method. At extremely high capillary pressure, irreducible water saturation of different rock types is shown to have significant overlapping, thereby introducing large uncertainty in rock typing. Across capillary transition zones, methods to correct for the presence of free water are necessary to extend the new rock typing method to multiple wells penetrating multiple capillary windows. In the aquifer window, the new method for rock classification is not practical because of the absence of capillary pressure. One important conclusion is that rock typing based on water saturation needs to be exercised with caution in different capillary windows to honor the reservoir's saturation-height behavior.
Flow of Polyacrylamide Polymers in the Near-Wellbore-Region, Rheological Behavior within Induced Fractures and Near-Wellbore Area
Authors: Zechner Markus , Buchgraber Markus , Clemens Torsten , Gumpenberger Thomas , Castanier Louis M. , Kovscek Anthony R. 
Published: June 2014

Abstract
The economics of polymer solution injection projects are dependent on the improvement of displacement efficiency over waterflooding, the injectivity of polymer solutions, and reduced lifting costs associated with oil production and reduced water cut. High molecular weight polyacrylamide polymers show shear-thinning behavior when measured in a rheometer while they show shear-thickening behavior in cores.
Micromodel experiments were used to investigate the rheological properties of polyacrylamide polymers at the high flow velocity conditions occurring in the near-wellbore region of wells. The results show shear-thickening characteristics. In addition, some plugging of the models by polymers was observed despite filtering of solutions. Also, core flood tests were performed. For the core-flood tests, severe degradation of the polymers was observed for high flow velocities.
The data gathered from the experiments was used to interpret the results of a polymer solution injection test performed in the 8 Torton horizon reservoir in Austria. Shear-thickening behavior of the polymers would lead to very high well-head pressures. Through introduction of the degraded polymer viscosity data obtained from the laboratory experiments, the injection pressure observed in the field is explained.
The field test showed that after a first phase of polymer solution injection under matrix conditions, a second phase with injection above the formation parting pressure (FPP) exists. To investigate the polymer rheology during this phase, micromodel experiments with various fracture geometries were conducted. The results show that within the induced fractures, polymer solutions show shear-thinning behavior and no substantial degradation of the polymers is seen. Owing to the low flow velocities through the fracture planes into the formation, also within the formation, no severe degradation of the polymers is expected.
Hence, high molecular weight polyacrylamide polymers should be injected above the FPP when high flow velocities are expected in the near-wellbore region and such injection is permissible.
Horizontal Well Fracture Initiation and Extension from Cemented Cased Wells
Authors: Daneshy Ali 
Published: June 2014

Abstract
This paper discusses two critical aspects of fracturing in cemented cased horizontal wells; the role of cement bond strength in fracture initiation, and the influence of spacing between perforation clusters on fracture width. It shows that opening of inclined and transverse fractures requires shear sliding between the formation and cemented casing. Strong cement bond or external casing attachments near the perforated interval hinder this shear sliding and hamper free opening of the fracture. If the initiated fracture is longitudinal, its opening causes tensile failure of the bond between casing and cement. This enhances the link between fracture and perforations and assists successful execution of the job. Close spacing between perforation clusters also results in fractures that are narrower than predicted by theories of fracture mechanics. Furthermore fracture width tapers quickly as it extend beyond the wellbore. Together these two mechanisms can explain why these types of fractures are known to occasionally encounter operational problems that include inability to inject at the planned rate during the early stage of each fracture and sudden screen-outs even with very low proppant concentration.
The paper offers perforation recommendations for enhancing borehole/fracture connection, as well as guidelines for successful execution of the treatment.
Modeling Viscosity Response of Fracturing Fluids from Flowback and Produced Water using Advanced Cooperative Optimization Algorithms
Authors: Fontenelle L. K. , Chen D. , Schnoor E. , Haggstrom J. , Perkins D. 
Published: June 2014

Abstract
As water management becomes a more prominent aspect of completion and production strategies within the oil and gas industry, some operators use flowback and produced water in place of fresh water during fracturing operations. These strategies help reduce the volume of fresh water used, thus lowering the environmental impact during completion and production operations. Because the highly optimized legacy formulations that provide optimal proppant transport have been formulated with relatively pure water sources, using flowback and produced water (which can contain dissolved minerals from the formation or byproducts of spent fracturing fluid) can prove challenging when trying to obtain predictable fracturing fluid properties. Reusing flowback or produced water typically involves reformulating the fracturing fluid through optimization for the specific source water, which can be a time-intensive process with high uncertainty associated with limited design experiments.
This paper presents a method for determining the chemical formulation to achieve a specific viscosity and time profile for a fracturing fluid based on the chemical constituents of the source water. The process uses neural network as a basis for modeling fracturing fluid viscosity over time after mixing. Once the viscosity is calculated from the empirical formulation, the chemical components are re-estimated through inverse neural network models to validate the previous selection. The optimization of the fluid formulation is implemented with a multiobjective genetic algorithm to determine the best selection of chemical components necessary for producing a specific viscosity profile. The results from the fluid simulations and actual testing are also discussed to demonstrate the different applications.
High Pressure Data and Modeling Results for Phase Behavior and Asphaltene Onsets of GoM Oil Mixed with Nitrogen
Authors: Hustad Odd Steve , Jia Na Jenna , Pedersen Karen Schou , Memon Afzal , Leekumjorn Sukit 
Published: June 2014

Abstract
This paper presents high pressure PVT measurements and equation-of-state (EoS) modeling results for a GoM oil and for the oil mixed with nitrogen in various concentrations. The data includes:
Upper and lower asphaltene onset pressures and bubble point pressures for the reservoir fluid swelled with nitrogen. At the reservoir conditions of 94 MPa (13,634 psia) and 94°C (201.2°F) asphaltene precipitation is seen after addition of 27 mole % of nitrogen. Viscosity data for the swelled fluids showing that addition of nitrogen significantly reduces the oil viscosity. Slim tube runs indicating that the minimum miscibility pressure of the oil with nitrogen is significantly higher than estimated from published correlations.
The data has been modeled using the volume corrected Soave-Redlich-Kwong (SRK) and the Perturbed-Chain Statistical Association Fluid Theory (PC-SAFT) EoS. While both equations provide a good match of the PVT properties of the reservoir fluid, PC-SAFT is superior to the SRK EoS for simulating the upper asphaltene onset pressures and the liquid phase compressibility of the reservoir fluid swelled with nitrogen.
Nitrogen gas flooding is expected to have a positive impact on oil recovery due to its favorable oil viscosity reduction and phase behavior effects.
Microresistivity Image Inpainting and Visualization
Authors: Assous S. , Whetton J.A. , Elkington P.A. 
Published: June 2014

Abstract
Borehole microresistivity images are an important source of high resolution information with broad application in geology and petrophysics. They contain large volumes of data which (for reasons of efficiency and reproducibility) makes it desirable to automate aspects of quantitative analysis such as feature extraction. One of several hurdles to be addressed in this challenge is the typically incomplete circumferential coverage of measurements from wireline tools (often less than 70%). Robust estimates of the missing information have been obtained by decomposing the measured parts into sparse representations of their morphological components using dictionaries of multi-scale, multi-orientation transforms; reconstructing these representations recovers missing information to an extent dependent on the dictionaries. In clastic rock formations the most useful transforms are found to be curvelets, which have been used to reconstruct a broad range of attributes including common continuous curvilinear features such as partial and full sinusoids, as well as textural elements. The method has been tested on full-coverage data from small diameter wells artificially obscured to simulate partial coverage. For images dominated by curvilinear features, reconstruction accuracy is 92% for 50% coverage loss (typical in 12.25 inch diameter wells), and at 30% loss (typical in 8.5 inch wells) images are almost indistinguishable from the original unobscured images for all apparent dip angles below near-vertical, regardless of degree of feature parallelism (or lack thereof). Successful reconstruction of near-vertical features (including those with complex boundaries such as breakouts) is more dependent on coverage loss, but in these cases the results are consistent with judgments made by human interpreters. The utility of these inpainted images is further enhanced by visualizations that improve on the universally-used static and dynamically normalized image displays by (for example) rendering wide dynamic range data without introducing unwanted artefacts. The image inpainting and visualization methods described are enablers for automated feature recognition.
65 Years of Fracturing Experience: The Key to Better Productivity is Not What we Have Learned but What we Have Forgotten and Failed to Utilize!
Authors: Syfan Frank E. , Palisch Terry T. , Dawson Jeffrey C. 
Published: June 2014

Abstract
Many engineers today do not have the training needed to fully understand the importance of fracture mechanics principles and are easily overwhelmed in trying to deal with proper proppant and fluid selections, perforation design and strategy, and on-site quality control of the fracturing process. The unfortunate reality is that many fracture designs are improperly engineered with critical reservoir and hydraulic fracture parameters either ignored or improperly addressed. Many completions are either marginally economical or produce at reduced commercial rates. Regardless of reservoir type, it is critically important to achieve a highly conductive hydraulic fracture that provides connectivity between the reservoir and the wellbore.
Since its inception, fracturing and completion knowledge has expanded exponentially allowing the oil and gas industry to develop ultra-low permeability unconventional reservoirs. During the 1980's and 1990's technology pioneers such as Holditch, Nolte, Warpinski, Veatch, and others, further developed the principles of fracturing which recognize the importance of critical fracture parameters and their effect upon initial productivity and ultimate recovery. These gains in expertise have resulted in unprecedented activity in the Bakken, Eagle Ford, Barnett, Haynesville, and Marcellus with increasing activity in new reservoirs such as the Utica, Niobrara, and Mississippian. Although each of these reservoirs is unconventional, each is uniquely different with respect to lithology, permeability, and hydrocarbon chemistry and interaction.
This paper will challenge the industry notion that infinitely conductive fractures are being placed in many unconventional completions. It further addresses the critical fracturing parameters required to achieve a high conductivity fracture, why they are important, and how to achieve proper proppant and fluid treatment designs. The importance of these fundamental principles is documented and illustrated by several case histories which demonstrate the value of achieving high conductivity fractures and the effects of improper design. This paper should be of great value to completion and operations engineers to help further their knowledge with regard to the importance of fracture conductivity and connectivity in all hydraulic fracturing applications.
New Blood to the E&P: How to Attract, Educate and Train New E&P Professionals
Authors: Suarez A. , Ford J. T. 
Published: June 2014

Abstract
The E&P industry is recognized to have cyclical behavior in respect to the need for new professionals, strongly linked to the level of activity related to the variations in oil and gas prices. The strong ups and downs on E&P activities create problems to properly solve the crew exchange equation with Companies' needs for new employees to be aligned with the retirement of experience professionals.
This paper presents the approach that Repsol has implemented, as a Global-Latin multinational IOC, in order to solve a much debated E&P industry problem on how to attract and hire first, and after that, how to educate and train for the E&P new professionals worldwide.
The much debated IOC's recurrent problem relates in this particular case to the needs of an IOC based within a nonbearing hydrocarbon country. It is them more important for the analysis to start with an inside reflection about the key differential characteristics of the Exploration and Production as an industry, then to follow with the identification of what are the common ingredients present on reputed good professional/managers from successful IOC's, thus to define what it is needed to be a successful professional on the E&P.
In order to be attractive and to attract the right profiles of students graduating at Universities worldwide, the IOC has to be aware on the big differences from how we do see ourselves and our industry, and in perspective, how are we perceived by society, as a way to understand, recognized and remediate the present lack of attraction or interest of our industry for the best talent coming out from Universities.
The above referred concerns are critical for Repsol as translated into the specific environment for a Latin-Global multinational that followed a strong period of growth expansion by acquisitions throughout the 90's, taking the Company into the top ten E&P IOC's. To overcome that problem, a tailor made approach was the selected solution, and an in-house intensive "Master E&P" course was designed in 1998-99, as a tool to attract and educate any new young professional recently graduated to be hired for its Upstream.
Successful HP/HT Drilling Through Innovative Practices: Sharing a Case Study of a Deep HP/HT Well
Authors: Syazwan M. , Yap Y. , Umar L. , Pepple M. M. 
Published: June 2014

Abstract
Despite the short planning time of 18 months and very limited geological data, TTD-1 HPHT Exploration well in Block SK of East Malaysia, was successfully drilled to its technical limit by adopting some innovative HPHT practices. Various technical challenges were successfully overcame including an abnormally steep pressure ramp (17 psi/ft), high mud weight (18 ppg), high overbalance (3,000 psi), narrow drilling margin (until 0.7 ppg window), wellbore breathing, pore pressure of 14,000 psi and temperatures of 325° F.
During drilling, the actual operating window was successfully mapped out in real-time. The lower boundary was defined by pore pressure modeling, MDT logging and dynamic flow checks using MPD. The upper boundary, fracture gradient, was derived from dynamic formation integrity tests & leak-off tests utilizing MPD. Other techniques such as use of smaller tubular, low-flow MWD tools and bridging agent also contributed to the success. Wellbore breathing was well controlled to a minimum level.
Various simulations have assisted the HPHT section to be drilled beyond conventional defined limits. Two real-time monitoring centers assisted in improving drilling efficiency and real-time decision making. The well highlighted limitations of acquiring formation pressure in tight formation using FPWD tools, life of MPD seal element and gas invasion in production zone cementation.
The authors will present and share the HPHT drilling practices adopted to successfully drill the deepest HPHT well to date for PETRONAS Carigali in Malaysia.