bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Investigation of Combined Electromagnetic Heating and Solvent Assisted Gravity Drainage for Heavy Oil Recovery
Authors: Hu Lanxiao , Li Huazhou Andy , Babadagli Tayfun , Ahmadloo Majid 
Published: May 2016

Abstract
Electromagnetic (EM) heating holds a large potential in heavy oil recovery since it can reduce carbon emission and avoid excessive water usage, and is applicable for water hostile reservoirs such as shale oil reservoirs. Combining solvent injection and EM heating might further reduce the energy intensity of the process. The merits of using solvent in EM heating include diluting heavy oil and thereby increasing its mobility, serving as a heat carrier by reinforcing heat convection in porous media and facilitating gravity drainage by forming a vapor chamber. Detailed experimental investigations are needed to investigate the mechanism of such a complex process and to specify the most influential factors of this hybrid and expensive process to determine optimal operational conditions. In this study, we conduct a series of laboratory experiments to investigate the mechanisms of combined EM heating and solvent assisted gravity drainage for heavy oil recovery.
During experiments, sand pack samples contained in Buchner filter funnel are placed in a microwave oven. Solvent injection can be initiated together with EM heating to simulate the hybrid process of combined EM heating and solvent assisted gravity drainage. We investigate the effects of influential factors on the process efficiency, including initial water saturation, solvent types (n-hexane and n-octane), introduction methods of solvents (injection or premixed with oil), combination strategies of solvent injection and EM heating (simultaneous or alternate means), and EM heating power. Temperatures of the sand pack and oil recoveries are simultaneously recorded. Experimental results show that combined EM heating and solvent assisted gravity drainage could effectively enhance heavy oil recovery compared with EM heating or solvent use alone. A higher heating power provides a faster temperature rise and earlier oil production in the sand pack. Moderate initial water saturation could increase the heating speed, leading to a higher oil recovery. Solvent injection can further enhance the viscosity reduction and swelling effect of heavy oil due to EM heating. Compared with n-hexane, n-octane provides higher vertical displacement efficiency and oil recovery under the same experimental conditions. Alternate EMH and solvent injection is more cost effective due to the lower energy consumption compared to the simultaneous EM heating and solvent injection.
Temperature-Dependent Deformation Prediction of Oil Sand by Coupled Geomechanical and Fluid Flow Modeling
Authors: Kashihara Koji , Rutqvist Jonny 
Published: May 2016

Abstract
Reservoir deformation during steam injection of SAGD operation can result in the increase in formation permeability that can positively impact to the bitumen production. The reservoir deformation behavior is controlled by the mechanical properties of oil sand, which are highly dependent on temperature. This work is focused on the temperature dependency of elastic properties of oil sand and its impact on geomechanical responses during a SAGD operation. Coupled geomechanical and fluid flow modeling technique is employed to illuminate the impact of the change in elastic properties to the reservoir deformation behavior.
Rock physics modeling is conducted at first for quantifying the temperature effect on the elastic properties of oil sand. Based on the investigation of log data from an actual SAGD operation field, we used the soft-sand model to calculate dry-frame elastic properties of the unconsolidated sand. We then applied and investigated several substitution methods to quantify the effect of the pore-filling bitumen on the elastic properties of the oil sand. We selected one of the solid substitution methods instead of Gassmann equation because bitumen behaves like solid at low temperature. The coupled hydraulic, thermal, and geomechanical simulator, TOUGH-FLAC, is used to investigate the effect of oil sand's elasticity on reservoir deformation behavior. The coupled modeling for SAGD is conducted for two simple cases; one case with the elastic properties at original reservoir temperature and the other case with the updated elastic properties considering the increased temperature. Comparison of the results from the two cases demonstrates the importance of considering the effect of temperature on the elastic properties of oil sand. This work is new in terms of combining rock physics modeling for quantitative description of the oil sand elastic properties and the coupled hydraulic, thermal, and geomechanical modeling considering the temperature-dependent elastic properties of oil sand.
Experimental Research on Thermal Cracking of Mudstone for Heavy Oil Thermal Production
Authors: Sun Feng , Xue Shifeng , Wang Haijing 
Published: May 2016

Abstract
Thermal production is an important heavy oil recovery method. While production, Steam injection triggers complex thermal and hydraulic processes which can dramatically alter the formation pressure and temperature leading to various changes within the reservoir as well as in the surrounding rock. This study is conducted to experimental research on the thermal cracking characters of mudstone barriers induced by heavy oil thermal production.
In this research, a thermal-mechanical coupling experimental device was developed. It can impose triaxial stresses and local wellbore high temperature to the rock sample. The temperature sensor was used to record the temperature change in the rock sample. Industrial computerized tomography (CT) technology was employed to scan the rock sample before and after the experiments, compared the changes of CT images and observe the thermal cracking characters of mudstone.
Mudstone of our laboratory studies were coring from the heavy oil reservoirs of Xinchun Oilfield (Xinjiang, China). The experimental results are listed as follows: (1) The thermal cracking developed with heating temperature increase. It's observed that the micro-fissures developed and connected to form larger fractures under 260°C. (2) The fractures propagate along the maximum/minimum horizontal stress direction on the surface of rock sample. CT images indicated that fractures propagation along the horizontal stress direction inside the sample. The propagating patterns also affected by the rock lithology, natural fissures and formation heterogeneity, etc. (3) The width of thermal cracking change with temperature, and the fractures closure during cooling from the growth temperature of 260°C to room temperature.
The above works show that thermal production affect the deformation and failure behavior of the mudstone barriers, it may cause the thermal cracking during multiple steam stimulation process. This will be instructive for optimizing the parameters of thermal production.
Accuracy and Reliability of a New-Generation Optical PT Gauge in a SAGD Field Trial
Authors: Ficocelli Peter , Baldwin Christopher , Vincelette Andre , Luckanachai Praise 
Published: May 2016

Abstract
Accurate and reliable subsurface pressure and temperature (PT) measurements facilitate SAGD production improvements. The dynamic nature of the SAGD process requires real-time control of subsurface temperature and pressure to better manage subcool and steam-oil ratio (SOR). With SAGD operating temperatures in excess of 250°C (482°F), the use of several fiber optic sensing technologies have been explored for more than a decade with variable results. The successful implementations are designed with proven optical technologies that can operate in the harsh and aggressive SAGD operating environments. Fiber Bragg grating (FBG) based array temperature sensing (ATS) and glass Cane™ technologies have been field proven to withstand ultrahigh temperature and hydrogen-rich SAGD environments.
We describe the unique aspects of fusing FBG and glass Cane technologies to provide a stable sensor for such harsh conditions. Qualification testing of the Cane-based optical PT gauge for accurate and reliable subsurface measurements and the results and analysis of the field trial are also presented for the initial 12-month period covering the conditioning and production phases.
The lab qualification and test plans are presented to validate the specifications of the optical Cane PT gauge designed for all SAGD operational conditions. The lab tests consisted of multiple thermal and pressure cycling, vibrations, and shocks. The performance of the gauge during the field trial is also described. The conditioning period provides an excellent reference point to validate the quality of the co-located pressure and temperature values reported by the PT gauge installed at the toe of the well. The gauge temperature and pressure readings are compared to surface readings and subsurface saturated steam conditions. Temperature and pressure readings at the toe of the well during the production phase are analyzed and compared to intake pump pressure measured using a reputable, earlier-generation, optical PT gauge.
The glass Cane PT gauge provides improved reliability and accuracy because of the novel rigid internal structure of the device that preserves the slimline 1/4-inch external diameter. The increased accuracy of the measurements enables operations at a lower subcool, thus increasing production while lowering cSOR. The increased thermal and pressure range allows short bursts of extreme-high-pressure fluctuations and operation in cyclic steam stimulation (CSS) and other thermal applications.
Completion and Well Spacing Optimization for Horizontal Wells in Pad Development in the Vaca Muerta Shale
Authors: Suarez M.. , Pichon S.. 
Published: May 2016

Abstract
In organic shales, hydraulic fracturing is an important parameter to optimize production of horizontal wells. For a lateral standalone, propped surface should be maximized to increase production (by increasing total proppant per well). While in the case of a pad, well spacing is an additional constrain for hydraulic fracture dimensions not to overlap with hydraulic fractures of neighboring offsets. Competition for production between laterals of a given pad should be minimized and is the result of both well spacing and hydraulic fracture design.
A numerical model coupling an explicit description of the hydraulic fracture geometry and reservoir simulation is proposed. Fracturing simulator accounts for material balance, geomechanics, interaction with natural fractures and stress shadowing within and in between fracturing stages.
Production interference is evaluated by comparing forecasted production of a lateral standalone (single well approach) against this same lateral while surrounded by offsets competing for production (multi well approach). Sensitivities are run assuming different completion and well spacing scenarios varying different parameters such as fluid and proppant volume, fracturing fluid type and staging.
Production interference between horizontal wells might reduce the final recovery of each individual well. However it provides an opportunity for simultaneous optimization of completion and well spacing to guide field development.
Hydraulic Fracture dimensions must match well spacing. Variation of fracture geometry along the lateral should be accounted for to evaluate well spacing and prevent the excessive growth of one single facture within a given stage. Completion design can be engineered by adjusting hydraulic fracture treatment volume, perforation cluster spacing or fracturing fluid viscosity to increase the overall consistency of the resulting fracture geometry and reduce effect of production interference between laterals of a given pad.
Novelty of the proposed methodology relies on the explicit description of the hydraulic fracturing geometry and direct coupling with reservoir simulation, not only for a single well, but considering a whole pad of horizontal wells as per a possible development of the Vaca Muerta shale.
Stimulation Optimization Using Engineered Diversion Workflow to Increase Wellbore Contact in Cemented Completions
Authors: Heaton N.. , Rondon J.. , Do T.. , Valenca A.. , Bruns J.. , Ohlson C.. , Eisele K.. , Paneitz J.. , Rollins B.. , Betts B.. , Cleaver Sarah 
Published: May 2016

Abstract
Completion techniques in the Middle Bakken formation have evolved over the years, with cemented Plug & Perf becoming the most common technique in recent years. It relies on stimulation of multiple clusters of perforations, normally 3-5, at one time. As previously demonstrated by multiple papers (SPE 173363, 144326, 167726, 174943) up to 40% of the perforation clusters remain un-stimulated. A novel engineered diversion workflow was implemented in 687 intervals of 20 Williston Basin wells. The purpose of this workflow is to increase cluster efficiency by stimulating the previously un-stimulated clusters. Results from each step down test and engineered workflow evaluation indicate increased cluster efficiency by up to 80%. Moreover, the success criteria for diversion pressure (1000 psi) was achieved on 81% of the intervals. Due to the success of these wells, this workflow has now become the standard diversion technique for one major operator in the Williston Basin.
A Utility Discrete Fracture Network Model for Field-Scale Simulation of Naturally Fractured Shale Reservoirs
Authors: Mi L.. , Jiang H.. , Tang L.. , Liu C.. , Li J.. , Wang Y.. , Cao Y.. , Killough J.. 
Published: May 2016

Abstract
Multi-scale fracture distribution is a unique feature in shale gas reservoirs development. For a reservoir engineer, establishing a utility method which can be both numerically efficient and practically accurate is the greatest challenge of shale gas reservoirs numerical simulation.
Naturally fractured shale gas reservoirs, which must be fractured before production, include many complex fracture networks (natural fracture and hydraulic fracture) that cannot be easily modeled by the simple continuous medium model (CMM), the discrete fracture model (DFM) or the discrete fracture network (DFN) model. In this paper, we propose a utility discrete fracture network (UDFN) model in which natural fractures are modeled by an analytic correction to matrix permeability, and hydraulic fractures are modeled by the DFN in which fractures are modeled explicitly. The partial differential equations are solved by Newton Raphson method through the C Sharp programing.
Case studies reveal that the UDFN's computational speed improves orders of magnitude than those of the DFN and DFM when dealing with the same problem, while the numerical result from UDFN method keeps enough accuracy to match the production curves as well as the results from the DFN. Meanwhile, the UDFN not only can simulate individual fracture's effects explicitly like DFM, but also can match up better to the field production than the DFM.
The method developed in this paper improved the simulation of multiple stage fractured horizontal wells performance in naturally fractured formations. It also makes the naturally fractured shale gas reservoirs numerical model much more concise and practical to the field case appplication.
Estimating Anisotropic Mechanical Properties and Stress Based on Measurements on Cuttings for Completion Quality: Methodology and Case Study in Vaca Muerta
Authors: Prioul R.. , Frydman M.. , Caniggia J.. 
Published: May 2016

Abstract
Unconventional plays such as Vaca Muerta are geologically complex and heterogeneous. Wells must be hydraulically fractured to produce, and material fabric, material properties, and in situ stress strongly influence this process. When logs are not available in the laterals, measurements on drill cuttings can be used to estimate anisotropic mechanical properties and stresses. The proposed method relies on two main steps. First, using one or more data-rich pilot wells, we define and calibrate rock physics and geomechanical models. The rock physics model provides the necessary relationship between the petrophysical volumes (mineralogy, organic matter and fluids) and the elasticity moduli, and the geomechanics model the relationship between elasticity moduli and the stress indices and the minimum stress. Second, in nearby lateral wells, we measure mineralogy and organic matter on cuttings samples using Diffuse Reflectance Infrared Fourier Transform Spectroscopy (DRIFTS) and apply the models to compute the elastic and stress properties. We illustrate this method using two vertical pilot wells that cross the Quintuco and Vaca Muerta Formations, Argentina, and one horizontal lateral well in Vaca Muerta. A complete suite of petrophysics logs have been acquired in both pilots, in addition to DRIFTS measurements on cutting samples in one of them and rock mechanics lab measurements on cores in the other one. In the lateral well, DRIFTS data have been acquired. We limit this paper to the construction, calibration and application of the rock physics model, as the construction and calibration of the geomechanical model is reported in a companion paper. We show that the sonic moduli can be reconstructed very accurately from the petrophysical volumes in the Quintuco and Vaca Muerta formations. The rock physics model highlights the impact of the high TOC in Vaca Muerta and of the mineralogy in Quintuco. The anisotropic shear moduli of Vaca Muerta are also predicted satisfactorily. To demonstrate the methodology, DRIFTS measurements on cuttings from the pilot well, are used to predict the sonic-derived moduli. Despite the sampling of the cuttings every few meters compared to the log data every 15 cm, we show an excellent consistency between DRIFTS- and log-derived elastic moduli. The model is then applied to DRIFTS data acquired on cuttings in a lateral, and the cutting-derived stress indices are computed. This method is both practical and theoretically sound. First, deterministic rock physics and geomechanics models are calibrated with high-resolution log data in a pilot well to relate petrophysical volumes to stress properties. Second, the use of spectroscopy logs in pilots and spectroscopy measurements on cuttings in laterals allow accurate estimation of stresses using cutting-based measurements in data-lean environments.
Case History: Hybrid Completion Method Employed for Longest Horizontal Unconventional Well in Vaca Muerta, Argentina
Authors: Welch M.. , Allen R.. 
Published: May 2016

Abstract
Argentina possesses some of the largest shale oil and gas reserves in the world and has the potential to benefit from the technologies currently used to extract unconventional shale resources in North America. Historically, Vaca Muerta resources were produced using vertical wells that were often stimulated in a few zones with plug-and-perf technology. Recently, operators started to adopt horizontal drilling and new multistage completion technologies to maximize access to the reservoir and increase production.
Although vertical wells are still popular, horizontal wells are gaining popularity in Argentina. Operators experimenting with horizontal wells are drilling longer laterals and are increasing the stage count within those laterals. Plug-and-perf is the typical completion system in horizontal wells; however, new technologies such as ball-activated sliding sleeve systems are being tested.
This paper will present the unconventional multistage hybrid completion of an exploratory well in the Neuquén Basin targeting the Vaca Muerta formation. The completion was comprised of 28 total stages: 13 open-hole, ball-drop sliding sleeve stages in the lower portion and 15 cemented plug-and-perf stages in the top portion. Disintegrating ball technology was used in conjunction with sliding sleeves so that post-frac intervention was eliminated in the deepest part of the well. The plug-and-perf stages were milled out after the fracturing treatment.
This well was the longest lateral drilled to date in Argentina at 2,016 meters (6,614 feet) and had the highest initial production rate of any well in Argentina's history. The lessons learned from this well can help Argentinian producers select the best completion method for large-scale development of unconventional resources in the Vaca Muerta Shale.
Is Induced Fracture Complexity Always Required in Unconventional Reservoir Stimulation?
Authors: Sierra Leopoldo 
Published: May 2016

Abstract
Induced fracture complexity maximization, in addition to the primary hydraulic fracture, to improve the recovery efficiency or productivity of gas or liquids in unconventional resource shale reservoirs has been accepted and fully implemented by the industry. As a result, stimulation fluids and/or completion strategies have been engineered to maximize induced fracture complexity in many unconventional reservoirs. In typical unconventional horizontal completions, induced fracture complexity is beneficial for the productivity of nanodarcy (nd) shales if conductivity is sustained in time, although induced fracture complexity may not be a requirement for all unconventional reservoirs, especially tight sands.
In some unconventional reservoirs, operators have observed similar productivity in wells with predominantly planar fractures compared to wells that appear to have more complex fractures. This paper, supported by extensive reservoir simulations, aims to develop criteria for situations in which induced fracture complexity and sustained conductivity are required and when they are not. The simulations include a reservoir permeability range of 10 nd to 0.001 md and a fracture complexity conductivity of 1 to 5 md-ft with and without stress dependence. The simulation results show that the fracture complexity with a constant and sustained conductivity (no stress dependent) are generally important for reservoir permeabilities lower than 100 nd for gas and 500 nd for liquid-producing reservoirs, but this benefit is minimized when the induced or existing stresses negatively affect the fracture complexity conductivity.
Based on these results, an optimized completion strategy is suggested to maximize the productivity or recovery factor (RF) in unconventional gas- and liquid-producing reservoirs.
Reservoir Flow Regime Assisted Multi-Segment Production Forecasting
Authors: Jeyachandra B.. , Sharma A.. , Dwivedi P.. , Gupta S.. 
Published: May 2016

AbstractIn many companies, production forecasting using multiple segments is gaining traction. Theoretically, the multiple segments are used to capture the different flow regimes in the reservoir over a period of time. A three-segment Arps decline model has been prevalently used, where, in early time, an Arps b parameter of 2 is used to denote transient flow;, during middle time, an b parameter of 0.2 to 1 is used; and, during late time, a b parameter of 0 to 0.2 is used to denote the boundary dominated effects. Choosing the segments and the b parameters was usually based on an educated guess about the reservoir and the visual observation of the changing slopes of decline.The three-segment model presupposes a reservoir behavior that may not be happening in the field, and varying operating conditions can skew the production rate slope and can mask the flow regimes observed in the reservoir, This, in turn, can lead to misleading forecasts. We are proposing a way to remove the guesswork from flow transition, the presupposition of flow regimes in the reservoir, and the masking effects of pressure using rate transient analysis.