bluuebunny/crossref_metadata_2025_split huggingface dataset:
Monitoring and Optimization of an In-Situ Combustion Pilot Applying STAR™ Technology
Authors: Gil E. , Quintero N. M. , Rojas L. A. , Fuenmayor M. , Farouq Ali S. 
Published: May 2015

Abstract
An in-situ combustion (ISC) pilot project was operated in the Quifa heavy oil reservoir in Colombia from Nov 2011 to July 2014. A modified inverted-nine spot pattern was used. As part of the project all wells were instrumented with pressure and temperature devices.
Parameters such as bottom hole temperature and pressure, gas composition (N2, CO2, CO, O2, SO4, H2S and hydrocarbons), water composition (minerals, pH), oil gravity and gas, oil and water production rates were measured and analyzed daily in order to control the combustion process resulting in improving the volumetric sweep efficiency and oil recovery factor. The continuing monitoring of these variables helped redirecting the combustion front, optimizing air injection and increasing production.
This paper introduces the STAR™ (Synchronized Thermal Additional Recovery) technology, based on ISC concepts, which aim increase the recovery factor and creating value in ISC in a heavy oil reservoir. STAR™ is based on the Synchronization Integrated Model (SIM), a suite of software applications which help to generate the main combustion-related parameters such as H/C ratio, oxygen utilization, air-oil ratio (AOR), air requirement, etc.; evaluate the process performance and identify the position of the combustion and fluids fronts in real time.
Case study of Solvent-Assisted Start-up in Fengcheng SAGD Project
Authors: Wu Yongbin , Li Xiuluan , Zhao Rui , Li Jun , Liu Xueqi , Zhou You , Du Xuan 
Published: May 2015

Abstract
Effective communication between the injector and producer with a reasonable conformance during SAGD start-up phase is crucial for the success of SAGD conversion and the following ramp-up phase. The start-up operation normally relies on heat conduction mechanism to establish heat and fluid communication between the wells. For super heavy oil reservoirs in Fengcheng project in China, since the pay zone has low thermal conductivity and extremely high oil viscosity, establishing the temperature profile required for SAGD conversion using conduction as the only heating mechanism is not efficient and can take 150 to 180 days to achieve. In order to shorten the circulation time and accelerate the ramp-up phase after SAGD conversion, an approach using solvent injection with steam simultaneously to enhance injectivity was successfully designed and implemented.
This paper reviews the design criteria, tests the thermal properties of cored samples, selects the typical wellpair based on geological modeling results, carries out the reservoir engineering design of solvent injection using CMG-STARS, and discusses the implementation performance of warm solvent injection in the start-up phase of a pilot wellpair in Fengcheng project. It also compares production responses of solvent-treated wellpair with other wellpairs with comparable reservoir properties in the same pad by conventional start-up to evaluate the performance of the designed pilot.
Impact of Formation Dilation-Recompaction on Development of Cyclic Steam Stimulation (CSS) in an Unconventional Heavy-Oil Reservoir: Seal's Cadotte Case
Authors: Jamaloei B. Yadali , Singh A. R. 
Published: May 2015

Abstract
Murphy has commenced horizontal CSS at Cadotte (Seal Lake, Peace River Oilsands). Cadotte is an unconventional reservoir due to compositional gradient, faulting, water pockets, and variations in oil viscosity, rock dilation/fracturing and pay-zone thickness. Gravity and viscosity are marked by declining quality with depth, biodegradation and compartmentalization.
High oil viscosity and low water mobility at Cadotte cause low initial injectivity. High injectivity during CSS is achieved by high pressure injection to fail the formation mechanically and trigger fracturing and deformation (dilation-recompaction triggers relative permeability hysteresis). Evidence of dilation at Cadotte includes greater steam injectivity than is expected and surface uplifts (larger than can be attributed to thermal expansion/tensile fracturing).
History-matching high injectivities is challenging when reasonable fracture lengths/rock compressibilities are used. To match injectivities, most simulations (Cold Lake/California CSS) have either used larger compressibility (‘spongy-rock’ approach) or long fractures. Spongy-rock approach predicts a steady increase in injection pressure, whereas in early cycles pressures increase and then level off for most of the cycle.
We describe enhancements made to a commercially-available simulator to incorporate modeling of deformation and relative permeability hysteresis to match injection/production pressures at Cadotte that are otherwise difficult to reproduce. The geomechanical model explains surface heave and high injectivity caused by dilation due to shear failure, increase in pore pressure/formation compressibility, and decrease in effective stress: A dilation pressure is specified, below which behavior is elastic (low compressibility) and above which, higher compressibility is used. Above a maximum porosity, further dilation is not permitted (low compressibility). The hysteresis model calculates grid-block relative permeabilities that lie on/between imbibition-drainage curves, making it possible to use laboratory-derived relative permeabilities and still match field WOR.
Impacts of dilation-recompaction factors (fracturing pressure, maximum pressure, dilation pressure, recompaction pressure, and formation compressibility) are quantified through field results, history-match/sensitivity analysis, performance optimization, and uncertainty assessment, utilizing reservoir simulation, Latin hypercube designs and Monte Carlo simulation.
Addressing geological/reservoir/operational variances, this modeling project helps determine optimum CSS development at Cadotte. It provides insight on how to screen the reservoir/operational parameters for successful CSS application in geologically-complex unconventional reservoirs with varying PVT behavior.
Mini-Frac Analysis in Oilsands and their Associated Cap Rocks Using PTA Based Techniques
Authors: Bachman Robert , Afsahi Behnaz , Walters Dale 
Published: May 2015

Abstract
The Alberta Energy Regulator (AER) requires mini-frac tests to be performed on thermal or polymer injection projects as part of the licensing process. Mini-fracture closure stress in the cap rocks is the key item used in determining the maximum operating pressure (MOP) for injection wells. The MOP has a significant impact on the economics of the project. This paper will establish a physics based interpretation method that covers all injection/fall-off mini-frac tests.
In the field, mini-frac tests are typically performed with multiple injection/fall-off cycles (usually 5 to 7 cycles) on each zone. Multi cycle testing is unique to the oilsands and their associated cap rocks. Multiple zones are also tested in a well, in both pay intervals (typically McMurray sands) and cap rocks (Clearwater shales etc.). Each cycle is analyzed for closure events and hopefully a consistent stress is found for each zone. Industry currently faces a conundrum as there is no agreement among analysts as to how to interpret these tests. As a result, reports submitted to the AER follow different methodologies. This may partially explain the wide range of reported closure stresses within individual basins.
This paper will show using field mini-frac data that traditional interpretation techniques can lead to ambiguities/incorrect interpretations. These issues can be overcome by using a pressure transient analysis (PTA) based interpretation approach. PTA has a long history of analyzing injection/fall-off and production/build-up tests where the rock fabric does not change during the test. The PTA interpretation methodology has remained remarkably consistent over the past 25 years. It can be summarized as follows: first identify flow regimes with a special kind of derivative plot, and second use flow regime specific specialized plots to calculate formation properties. This paper will show that PTA can now also handle dynamic fracturing (i.e. mini-fracturing) and all of its associated special cases; which include pressure dependent leak-off, height recession/transverse storage and tip extension.
Mini-frac analysis is now just a sub-set of the larger PTA methodology. It has the added advantage in that a rules based procedure can be established for the entire interpretation workflow.
Heavy Crude Oil Dewatering Processes for Fluid Property Measurements: Comparison, Impact, and Suitability of Methods
Authors: Zhao Hongying , Memon Afzal , Gao Jinglin , Taylor Shawn David , Sieben Donald , Ratulowski John , Alboudwarej Hussein , Pappas James , Creek Jefferson 
Published: May 2015

Abstract
A representative clean heavy oil sample (&lt;1% BS&W) is crucial to obtain accurate fluid property data, which are required for heavy oil production, processing, and transportation designs. However, it is always a challenge to remove water from a heavy oil sample (&lt;20° API) due to its near-water density (10° API) and high viscosity (slow separation). The objectives of this study include qualifying three heavy oil dewatering methodologies, determining their impact on heavy oil properties, and recommending suitable method(s) for preparing heavy oil samples for laboratory fluid phase behavior and property measurements.
The three demulsification methods – centrifugation, the addition of demulsifiers, and distillation – were systematically evaluated and compared. Three dead heavy oil samples ranging from 20 to 11 API gravity degrees and with viscosities ranging from 100 to 5,000 mPa·s at 310.9 K (38°C) were selected. A stable emulsion with a 30 vol% synthetic brine were prepared using each heavy oil sample, which was used to evaluate each of the demulsification methods. Viscosity, density, and composition of the dewatered samples were measured and compared with the corresponding original oil data.
This study demonstrated that centrifugation had the minimum impact on sample properties, although it was difficult to reduce the residual water content below the dewatering target of less than 1 wt%, especially for sample densities nearest the water density. The addition of chemical demulsifiers followed by mild centrifugation resulted in samples that met the dewatering target. The change in fluid properties caused by the demulsifier method was similar to the minor changes observed by the centrifugation method. Distillation could remove water from all three emulsions to below the dewatering target, if appropriate experimental procedures were followed. However, distillation had the strongest impact on dewatered oil properties due to the loss of light/intermediate components, despite precautions to minimize the mass loss.
In current open literature, the effect of the heavy oil sample preparation procedure on the measured heavy oil properties and PVT data is rarely reported in detail, which makes it a challenge to properly perform the data interpretation and use them in relative modelling and design work. This simple, systematic study provides insight into the effect of three common dewatering procedures and guidance for developing reliable laboratory sample preparation protocols for heavy oils.
Non-Linearity and Stress-Dependency In Unconsolidated Formations and the Associated Impacts on Thermal Recovery: An Analytical Assessment
Authors: Hosseini Amir H 
Published: May 2015

Abstract
In thermal recovery from unconsolidated oilsands reservoirs and in association with fluid mobility, formation compressibility and modulus of elasticity are closely related to pressure transient and stress redistribution behavior, which can collectively affect the steam chamber development. The non-linearity and stress-dependency in bulk compressibility and modulus of elasticity of rocks has been captured through the development of elegant constitutive models (e.g. nonlinear elastic hyperbolic model) and has been readily integrated into coupled reservoir-geomechanical simulation packages. To assess the significance of these nonlinearities for reservoirs with different initial stress states, this paper presents an analytical study where the associated impacts on the redistribution of stress (stress-paths) and the onset of geomechanical mobilization (shear dilation) under the assumption of uniaxial deformation are quantified. Within the scope of this paper, (semi-) analytical modeling is conducted while special attention has been devoted to (1) the vast range of depths of the existing oilsands reservoirs and the associated implications on the initial stress distribution as well as stress redistribution due to steam/water injection, (2) the impacts on the onset of geomechanical mobilization within the practical ranges of injection pressures, and (3) the evaluation of geomechanical mobilization potential for thermal (steam injection) versus non-thermal (cold water injection) pressurization. The results show that (1) the potential impact of stress dependency on the variability of the geomechanical properties (modulus of elasticity, Poisson's ratio and formation compressibility) is more significant for shallow reservoirs as compared to mid-depth and deep reservoirs, (2) the injection pressure required to onset the geomechanical mobilization may be under/overestimated if the non-linearity in the mechanical properties is overlooked, and (3) the thermal geomechanical mobilization (steam injection) may have a higher potential within practical ranges of operating pressures as compared to non-thermal techniques (cold water injection), especially for shallower reservoirs. The inherent limitations of the analytical workflows as well as the requirements of supporting efforts through coupled reservoir-geomechanical simulations are also discussed.
Surveillance Techniques for Recovery Factor Optimization in a High Viscosity Unconsolidated Sand Reservoir
Authors: Aguero S. D. , Best R. Ortiz , García M. Perea , Cremonini A. S. 
Published: May 2015

The current article describes waterflooding surveillance techniques applied in El Corcobo Norte and nearby fields, operated by Pluspetrol S.A., in the northeast margin of Neuquén Basin. The main productive target is the Centenario formation, a relatively shallow unconsolidated sandstone reservoir. The API gravity is 19° and the oil viscosity under reservoir conditions is between 150 and 250 cP.
Producer and injector well completion is performed applying the so called CHOPS technique (Cold Heavy Oil Production with Sand), which consists of promoting sand production during completion by producing at high rates. Sand production causes the generation of caverns and “wormholes” that increase productivity/injectivity indexes that are necessary to achieve economical productions. Due to the low original reservoir pressure (30 kg/cm2) and fast decline of primary production, it was necessary to support reservoir pressure from the very beginning of the field's operation. The heterogeneity caused by the CHOPS technique and the high oil viscosity represent a challenge for waterflooding performance. However, important waterflooding response was observed in producer wells. Strong water wettability of the reservoir rock and reservoir continuity favor displacement and volumetric efficiencies.
Waterflooding surveillance relies on strong data acquisition of injection and production, which allows, among others, daily injection/production parameter revision, weekly revision for producer well extraction, monthly revision for rates and VRR (voidage replacement ratio), and processing factors (produced or injected pore volumes a year). With the objective of promoting a homogeneous sweep and lower water cuts in producer wells a strategy was designed to determine specific injection and production rates.
The constant application of this surveillance strategy and constant modification of injection and production regime have allowed to obtain recovery factor as high as 20% in the more mature zones in only 6 years of production and to sustain a production plateau during this time. On the other hand, this continuous modification generates uncertainties for forecasting the behavior of the field production and therefore the ultimate recovery factor.
Additionally, actions taken to increase oil production in the field have led to severe producer-injector channeling issues, which affect negatively in oil recovery and need to be prevented in order to optimize ultimate recovery.
Regarding this topic, empirical limits were defined to avoid channeling between producer and injector, and also remediation techniques were developed to recover channeled wells.
Rigorous coupling of geomechanics and thermal-compositional flow for SAGD and ES-SAGD operations
Authors: Garipov T. T. , Voskov D. V. , Tchelepi H. A. 
Published: May 2015

Abstract
Steam Assistant Gravity Drainage (SAGD) is widely used to recover heavy oil and bitumen reservoirs. Typical SAGD operations involve a pair of horizontal wells separated vertically. Steam, or a steam-solvent mixture (e.g., Expanding- Solvent SAGD), is injected into the upper well to form a steam chamber and mobilize oil, which drains to the lower production well. Significant mechanical stresses associated with this process can increase the risk of fracturing the reservoir, or cap-rock. We perform a fully-coupled thermal-compositional-mechanical numerical simulation of SAGD and ES-SAGD processes for a typical bitumen reservoir in the Fort McMurray region of Alberta, Canada. A mixed finite-volume approximation for the flow and a Galerkin finite-element approximation for the mechanics are used, and the resulting set of nonlinear equations are solved using a fully implicit formulation. The two discretizations share the same unstructured grid. We demonstrate that thermo-mechanical effects can be quite significant in SAGD operations. The sharper gradients associated with the standard SAGD process increase the risk of damaging of the cap-rock. On the other hand, ES-SAGD operations lead to more dispersed temperature and pressure distributions, which decreases the possibility of damaging the cap-rock.
Bridging the Gap: An Integrated Approach to Solving Sustained Casing Pressure in the Cana Woodford Shale
Authors: Landry G.. , Welty R. D , Thomas M.. , Vaughan M. L. , Tatum D.. 
Published: May 2015

Abstract
Many wells in the Cana-Woodford shale suffer from chronic sustained casing pressure (SCP). With more stringent SCP regulations on the horizon, operators need a way to prevent SCP effectively during primary cementing because remediation can prove costly or detrimental to business. At the start of a recent project virtually all cement bond logs showed poor coverage and a lack of zonal isolation. Due to the poor cement sheath bonding, SCP was occasionally observed before fracturing and almost always occurred after fracturing. This paper discusses a method that has resulted in a high success rate in preventing SCP - where previously, failure was common.
An integrated approach between multiple service company operations and operator was used to address the cement bonding issues and the long-term integrity of the cement sheath. The ultimate objective was to not have any SCP on any annulus of the well for the lifetime of the well. Initially, high-resolution ultrasonic bond logs were run to evaluate slurry placement and methodologies. Placement of the slurry around the casing was then optimized using laboratory testing and modeling software based on lessons learned from log evaluation. The success of the engineered approach was evaluated with ultrasonic logs utilizing flexural attenuation, thereby validating simulations. Finally, the long-term set cement properties were evaluated through the use of stress analysis software, which simulated stimulation treatments and their effect upon the mechanical properties testing.
Cement placement was optimized with an oil-based mud (OBM) recovery in mind. Using simulation software, centralization of the production casing was evaluated, and an optimized frictional pressure hierarchy then designed. A cement bond log was run to evaluate the proposed solution. The results proved that zonal isolation was achieved throughout the curve and into the casing-to-casing section. The logs showed excellent coverage in this well relative to its peers and the best results to date. Continued monitoring showed no casing pressure after stimulation and 1.5 years of production. The operator's other seven wells in this section, which did not have the engineered approach applied, showed SCP immediately after stimulation.
The engineered placement method ensured complete cement coverage around casing through an optimized frictional pressure hierarchy. This multilayered approach using mechanically optimized slurries with different mechanisms of action, including self-healing, provided a comprehensive cementing portfolio that contained layers of contingency. To date, the method has a high success rate in the prevention of SCP in the Cana-Woodford shale. Unconventional gas/liquid plays have changed our industry. The methodology outlined in this paper has been successful, and the lessons learned can be applied to many other unconventional gas/liquid plays that include fracturing stimulation for development.
Smoke or Fire? Acute Pancreatitis and the Liraglutide Trials
Authors: Gale Edwin A.M. 
Published: May 2015

Over the past few years, substantial clinical data have been presented showing that incretin-based therapies are effective glucose-lowering agents. Specifically, glucagon-like peptide 1 receptor agonists demonstrate an efficacy comparable to insulin treatment with minimal hypoglycemia and have favorable effects on body weight. Thus, many of the unmet clinical needs noted from prior therapies are addressed by these agents. However, even after many years of use, many continue to raise concerns about the long-term safety of these agents and, in particular, the concern with pancreatitis. This clearly remains a complicated topic. Thus, in this issue of Diabetes Care, we continue to update our readers on this very important issue by presenting two studies evaluating incretin-based medications and risk of pancreatitis. Both have undergone significant revisions based on peer review that provided significant clarification of the data. We applaud both author groups for being extremely responsive in providing the additional data and revisions requested by the editorial team. As such, because of the critical peer review, we feel both articles achieve the high level we require for Diabetes Care and are pleased to now present them to our readers. In keeping with our aim to comprehensively evaluate this topic, we asked for additional commentaries to be prepared. In the narrative outlined below, Prof. Edwin A.M. Gale provides a commentary on the report that focuses on clinical trials of liraglutide in the treatment of diabetes. In the narrative that follows Prof. Gale’s contribution, Dr. Laurent Azoulay provides a commentary about the remaining uncertainty in this area and also discusses the results from a nationwide population-based case-control study. From the journal’s perspective, both of the articles on pancreatitis and incretin-based therapies reported in this issue have been well vetted, and we feel both of the commentaries are insightful.
—William T. Cefalu
Editor in Chief, Diabetes Care