bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of the Clearwater Formation Caprock for a Proposed, Low Pressure, Steam-Assisted Gravity-Drainage Pilot Project in Northeast Alberta
Authors: Uwiera-Gartner M. M. , Carlson M. R. , Palmgren C. T. 
Published: October 2011

Abstract
In northeast Alberta, Canada, steam-assisted gravity-drainage (SAGD) is used to produce bitumen from the Athabasca oil sands. In some regions, bitumen resources are located within 100 m of the ground surface and have average caprock thicknesses of about 50 m. The caprock unit overlying the bitumen reservoir is comprised mainly of mudstones and shales from the Early Cretaceous, Wabiskaw Member and Clearwater Formation. These shales form a baffle, impeding vertical steam migration and confining the stress and strain fields developed during the SAGD process, which are crucial for maintaining caprock integrity at SAGD operations.
In May 2006, an unexpected, catastrophic failure of the caprock seal occurred at the Joslyn Creek SAGD project, resulting in a steam release, which caused considerable caprock and ground surface deformation. Because of this failure, the Alberta Energy Resources Conservation Board modified the existing application guidelines and directives to include an assessment of caprock integrity at the maximum operating pressure specified for the thermal project applications.
The authors recently completed a core based, caprock integrity assessment for a proposed, shallow, low pressure SAGD, pilot project in northeast Alberta. This paper describes the information reviewed, assessment method and results of this study. From this evaluation, information about the geomechanical characteristics, the potential for containing the induced stress and strain fields and the geologic risks associated with caprock integrity for the proposed pilot project were determined. An assessment of the underburden seal was also performed as this seal can influence caprock properties. Results of the underburden seal assessment are also presented.
Wettability Alteration in High Temperature and High Salinity Carbonate Reservoirs
Authors: Sharma Gaurav , Mohanty Kishore K. 
Published: October 2011

Abstract
The goal of this work is to change the wettability of a carbonate rock from mixed-wet towards water-wet at high temperature and high salinity. Three types of surfactants in dilute concentrations (&lt;0.2 wt%) were used. Initial surfactant screening was done on the basis of aqueous stability at these harsh conditions. Contact angle experiments on aged calcite plates were done to narrow down the list of surfactants and spontaneous imbibition experiments were conducted on field cores for promising surfactants. Secondary waterflooding was conduceted in cores with and without the wettability altering surfactants. It was observed that barring a few surfactants, most were aqueous unstable by themselves at these harsh conditions. Dual surfactant systems, a mixture of a non-ionic and a cationic surfactant increased the aqueous stability. Some of the dual surfactant systems proved very good for wettability alteration and could recover 70-80% of OOIP during spontaneous imbibition. Secondary waterflooding with the wettability altering surfactant increased the oil recovery over the waterflooding without the surfactants (from 29% to 40% OOIP).
The World's Deepest Frac-Pack Completions Using a Single-Trip Multi-Zone System: A Gulf of Mexico Case Study in the Lower Tertiary Formation
Authors: Ogier K. Scott , Haddad Ziad , Moreira Oswaldo , de Moraes Flavio Dias , Shipley Jonathan 
Published: October 2011

Abstract
Single-trip multi-zone (STMZ) Frac-Pack completions can significantly reduce the time to complete wells with long productive intervals. This technique was used successfully in two Lower Tertiary completions in the deepwater Gulf of Mexico (GOM) Cascade/Chinook project in 2010 (26,000 ft TVD, 8900 ft water depth). With interval lengths exceeding 1,000 ft, reservoir pressures greater than 18,500 psi, and bottomhole temperatures higher than 250°F, these STMZ completions were the first of their kind.
With a STMZ completion, all completion intervals in a well are perforated at once. Then all the lower completion hardware (screens, sleeves, packers, etc.) is assembled and run in the well and the packers are set. Through the manipulation of sliding sleeves, each interval is individually opened and frac-packed sequentially from the bottom interval to the top. Before moving to the next interval, the sleeves are closed and pressure tested, providing isolation between the wellbore and the reservoir.
The steps are repeated until all the intervals are stimulated. The STMZ system saves a great deal of rig time over conventional stacked frac-pack systems by significantly reducing the number of trips in and out of the well with the work string.
This paper discusses the challenges, planning, execution, and results of these STMZ completions with a focus on the downhole completion hardware. Also discussed are some planned modifications to the system that will reduce risk and improve performance in the future.
Potential Pitfalls from Successful History-Match Simulation of a Long-Running Clearwater-FM SAGD Well Pair
Authors: Doan Q. , Ali S. M. , Doan M. 
Published: October 2011

Abstract
Canada's oil sands deposits in northern Alberta contain more than 1.35 trillion barrels (~215 billion m3) of bitumen. Such a large resource base, even allowing for (relatively) low recovery factors, still constitutes the world's second largest oil reserves (behind only Saudi Arabia's). In-situ recovery technologies for these deposits, in view of the extremely viscous bitumen typically existing in them, commonly require thermal heating and/or solvent dilution to mobilize the bitumen and enable it to be produced. Steam-Assisted Gravity Drainage (SAGD) and Ccyclic-Steam Stimulation (CSS) are currently two technologies accounting for the bulk of in-situ bitumen production in Canada.
This paper briefly reviews key developments of the SAGD process. It next analyzes the production performance of a long-running Clearwater-FM SAGD well pair, followed by the presentation of history-match simulation results for this SAGD well pair. Discussion of the results is given from the viewpoint of Level-I (matching rates, volumes, fluid ratios) and Level-II (matching steam chamber behaviour) history match. These results demonstrate clearly the challenges of history-match simulation for the SAGD process, as well as the utility (or lack of) of Level-I and Level-II matches. Discussion and conclusions are also offered of the potential pitfalls associated with interpretation of history-match simulation results for the SAGD process, and subsequent implications for SAGD reservoir management.
Particle Size Distribution-Engineered Cementing Approach Reduces Need for Polymeric Extenders in Haynesville Shale Horizontal Reach Wells
Authors: Williams H. , Khatri D. , Vaughan M. , Landry G. , Janner L. , Mutize B. , Herrera M. 
Published: October 2011

Abstract
Recently discovered Haynesville gas-shale trends have transformed the regional and global outlook for natural gas supply, but offer unique challenges to the operator and service company during mud removal, cementing, and completion operations. To counter these challenges, recent advances include improved drilling, centralization, mud-removal, cementing best practices and implementing a broad particle size distribution-engineered (PSDE) cement system for use in high temperature horizontal intervals reaching across high pressure, high temperature (HPHT) gas-shale trends. For PSDE cement systems, rheological properties are based on inter-particulate interactions to achieve the desired viscosity and not based on polymeric extenders/antisettling additives. Since PSDE fluids are not dependent on polymeric thermal thinning behavior, they demonstrate consistent rheological properties over a wide temperature range and are more suitable for placement in narrow annuli.
In this paper, Haynesville cement placement and extensive laboratory testing best practices will be discussed. Also, a case study will be presented that describes a typical and successful placement of PSDE cement fluid in the Haynesville shale at bottom hole circulating temperatures (BHCT) up to 182 °C [360 °F] and bottom hole pressures (BHP) up to 82.7 MPa [12,000 psi]. After successful job completion and time allowed for the cement to properly set, an annular seal pressure test was successfully completed, with minimal pressure bleed-off.
Since introduction in 2009, over 390 production jobs have been successfully cemented using the PSDE cement technology, with 99.5% placement success rate. Acquired well head pressures (WHP) were less than or equal to predicted WHP for most production jobs. PSDE Cement Technology has become a proven approach for cementing high-temperature, horizontal tight-gas shale environments in relatively narrow annuli where fluid stability and zonal isolation are needed during placement and subsequent hydraulic fracturing treatments. This approach has been applied to Haynesville and Eagleford shale horizontal reach production wells and is being investigated for use in other high temperature, high pressure applications.
Integrated Capacitance Resistive Model for Reservoir Characterization in Primary and Secondary Recovery
Authors: Nguyen Anh P. , Kim Jong S. , Lake Larry W. , Edgar Thomas F. , Haynes Byron 
Published: October 2011

Abstract
This paper presents a new procedure to obtain unique estimates of interwell connectivities, pore volume, and productivity index in primary and secondary recovery. This method approaches the problem by analytically integrating the simplified continuity material balance equation. The proposed procedure uses linear multivariate regression on rate, initial reservoir pressure and bottom hole pressure (BHP) data. The method quantifies compressible pore volume – the capacitance, productivity index (PI), and degree of communication between well pairs – the resistance to flow. Hence, it is called the integrated capacitance-resistive (ICR) model.
The ICR model fits cumulative production against rates, BHP, and cumulative water injected. For primary recovery, the model has been validated on synthetic field data generated by numerical simulator, covering the effects of initial oil saturation, heterogeneity, and number of wells. The model was also tested on a real field. For secondary recovery, the procedure was tested on synthetic fields with high permeability channels.
In all primary recovery synthetic fields tested, good fit and less than 13% error of estimated pore volume and PI were observed. Real field application also shows good agreement with geological knowledge. For waterflooded synthetic fields, the estimated parameters are consistent with the geology and the results obtained from the capacitance resistive model (CRM) fit. The confidence intervals of the parameters are narrow enough to conclude regression coefficients are statistically significant. Hence, the ICR model can be used to quickly estimate reservoir properties and infer interwell communication in primary and secondary recovery from available data with high confidence.
The ICR model is comparable to CRM in terms of number of inputs. Hence, both models can be used in large fields with hundreds of wells. However, the nature of the CRM's nonlinearity makes it difficult to establish confidence intervals of the model parameters and obtain a unique set of model parameters for a large number of wells. In the proposed method, a unique solution can always be obtained regardless of the number of parameters via linear regression. The simpler formulation of the ICR model would reduce the computation time and easily establish the confidence intervals of model parameters.
Modeling of Transport Phenomena and Multicomponent Sorption for Shale Gas and Coalbed Methane in an Unstructured Grid Simulator
Authors: Leahy-Dios Alana , Das Mita , Agarwal Anshul , Kaminsky Robert D. 
Published: October 2011

Abstract
Shale gas and coal bed methane (CBM) assets have become increasingly important over the last decade, and are expected to become major energy sources for the future generations. However, there are unanswered fundamental physics and transport questions for each of these resources. Various physics-based approaches have been proposed and implemented to understand and simulate the flow mechanisms. However, the connectivity of organic and mineral matter is not fully understood and thus the exact transport mechanism in shale gas is still uncertain. This in turn can significantly limit the quality of resource potential and production forecast estimates.
This work addresses the challenges for shale gas and CBM simulations and presents a coupled sorption-transport model for both assets, along with its implementation in an unstructured grid compositional simulator. The models presented have been designed to capture key physics while still being straightforward to apply. A model for handling multicomponent isotherms based on pure component data is described. Existing experimental data were fit with the model and the results are discussed. A general transport mechanism workflow, which can be applied to both shale gas and CBM, is proposed. Results and findings are provided for the overall proposed scheme from gas desorption in the organic matter to the different transport mechanism in the matrix and the fractures.
Improved Upscaling for Flow Simulation of Tight Gas Reservoir Models
Authors: Zhou Yijie , King Michael J 
Published: October 2011

Abstract
Tight gas and shale gas reservoirs provide almost half of the current U.S. domestic gas production, with significant projected increases in the next several decades. These reservoirs constitute an important play type, with opportunities for improved reservoir management in the optimization of depleted volumes as functions of well spacing and fractured well design. Reservoir simulation, together with detailed 3D geologic models, may be used for improved management, but only if the flow simulation through these models can capture the essential heterogeneity and 3D continuity of these intermittently connected rock packages. The current work will examine tight gas reservoirs, but we recognize that similar issues will arise in source rock plays.
The current approach has three key technical elements: (1) We explicitly preserve the local continuity of the reservoir sands in the geologic model through the design of the simulation grid. Each simulation cell is a 1×1×N amalgamation of the geologic scale corner point cells, where "N" will vary depending upon the local sand thickness. (2) We have developed a "Well Index" based upscaling, to determine the upscaled permeability and which preserves the local reservoir quality. It does not require knowledge of the well locations within the upscaled simulation model, but it will preserve the performance of these wells. (3) The heterogeneity within each sand is preserved through the use of transmissibility upscaling, which we show performs systematically better than the usual permeability upscaling. In combination, these three elements provide simulation results which are almost indistinguishable from the fine scale model. We also examine additional approximations in which we further coarsen the model areally, and reduce the simulation time further. We develop and demonstrate our calculations on a sector model taken from the center of a full field onshore U.S. tight gas reservoir. The results are then validated using the full field model.
Our approach differs from earlier studies which have attempted to preserve the global heterogeneity of the reservoir models though layer-based statistical calculations. Although these statistical approaches are superior to uniformly coarsened models, they are not as robust or as accurate as the current work constrained by local continuity. Our approach also differs in the use of accurate property upscaling techniques that simultaneously preserve the internal contrast of permeability within each sand, and the performance of wells within the model.
A Practical Approach to Determine Low-Resistivity Pay in Clastic Reservoirs
Authors: Chu Wei-Chun , Steckhan Jan 
Published: October 2011

Abstract
Low-resistivity pay (LRP) has been a challenging problem in formation evaluation for many years. This is because conventional petrophysical interpretations are unable to identify pay intervals in low-resistivity reservoirs. This paper lays out a robust workflow for identifying LRP in thinly laminated sands with silty and/or shaly layers.
The workflow is essentially a two-step process which integrates data from gas while drilling (GWD), conventional logs and nuclear magnetic resonance (NMR) logs which identify potential pay intervals for further examination using wireline formation tester (WFT). This approach allows one not only to identify pay intervals but also their phase and their flow characteristics without the need of a conventional drill-stem-test (DST).
It is common for LRP to have high water saturation (60-70%) computed by conventional petrophysical interpretation while producing sustained water-free oil for few years. A petrophysical study was undertaken to integrate core data analyses including conventional, NMR and mercury injection capillary pressure (MICP). Data from over 100 sidewall cores (SWC) were examined. This novel approach for estimating irreducible water saturation (Swi) was developed based on
A good relationship was recognized between Swi from capillary pressure data as compared to that estimated from NMR de-saturated core. A correlation was established between Swi of de-saturated core and T2, LM. A validation was performed for zones producing water-free oil to link between NMR-MICP core analysis and NMR logs, using the following two methods for estimating Swi from capillary pressure data that is computed with knowledge of the height above free water level (FWL), T2, LM of NMR logs using the correlation developed in Step 2.
The benefits of this methodology are that it improves decision in well completion, predicts well performance accurately and reduces uncertainty in reserve estimation. In addition, it allows the user not only to identify zones of pay that would have been missed using conventional analysis, but also to estimate FWL elevations with higher accuracy from a saturation height model (SHM). Saturation profiles derived by this approach and those ones modeled from saturation height equations based on MICP capillary pressure data can be fitted better due to substantial reduction in uncertainties of log derived saturation data. Consequently the initialization of in-place volumes for hydrocarbons will be enhanced.
Stress Shadowing and Microseismic Events: A Numerical Evaluation
Authors: Nagel Neal B. , Sanchez-Nagel Marisela 
Published: October 2011

Abstract
In horizontal well shale completions, multiple stages, each often with multiple clusters, are used to provide sufficient stimulated area to make an economic well. Each created hydraulic fracture alters the stress field around it. When hydraulic fractures are placed close enough together, the well-known stress shadow effect occurs in which subsequent fractures are affected by the stress field from the previous fractures. The effects include higher net pressures, smaller fracture widths and changes in the associated complexity of the stimulation. The level of microseismicity is also altered by stress shadow effects. For example, it is commonly seen that the number of microseismic events is significantly reduced from the toe to the heal of the well, where the first frac stage is conducted at the toe of the well.
In this paper, we present the results of a numerical evaluation of the effect of multiple hydraulic fractures on stress shadowing as a function of fracture spacing, shale rock mechanical properties, and the in-situ stress ratio. In addition, utilizing the inherent ability of discrete element models to evaluate shear and tensile failure along fracture surfaces, shear failure, as a proxy for microseismicity, is evaluated as a function of fracture-induced stress and stress shadowing. The results of the study provide a means to optimize shale completions by understanding the effect of stress ratio, rock mechanical parameters, and hydraulic fracture spacing on the stress shadow effect and the potential for changing fracture complexity.
Case Studies of an Innovative New Drilling Tool Using Rate of Penetration Modulation
Authors: Farley Steven Reid , Maranuk Christopher A. , Jasper Clint 
Published: October 2011

Abstract
Mud motors have been used for decades to help steer wells in a desired direction. They are typically oriented with a bent sub in the motor and are pointed in the planned direction to kick-off the well or drilling section. They use a combination of rotating and sliding to keep the well on target and, depending on various drilling and formation parameters, may need to slide the majority of the time to maintain hole projection. Sliding often creates issues with hole cleaning, ledging, and decreased rate of penetration (ROP). Rotary-steerable tools, on the other hand, continuously rotate in the hole eliminating many of the problems associated with an oriented positive displacement motor (PDM). A new system for wellbore directional control has been developed that uses a positive displacement motor and a bent sub to provide continuous rotation throughout the wellbore. This new system offers many advantages of a rotary-steerable system but also capitalizes on the proven technology of a positive displacement mud motor.
Steering is accomplished by managing the pressure fluctuations within the drillstring, creating slight oscillations in the flow rate through the mud motor. These controlled undulations in flow rate allow high-frequency variations in drilling parameters to steer the well in any targeted azimuth. If the planned objective cannot be achieved using ROP modulation in rotary mode, then the motor can still be oriented in the desired direction and slid, using the more conventional mud motor orienting technique.
This paper will review several operations where the new steering system was used to help drill the well. It will discuss the operational challenges of drilling the wells, as well as how the new system helped overcome those challenges.