The development of unconventional hydrocarbons has become a significant resource, leading to growth of worldwide oil and natural gas supplies. Hydraulic fracturing has been successfully employed for unconventional oil and gas recovery for decades. In recent years, the rapid progress of technology has led to reduced gas prices and a shift in focus to liquid extraction.
However, liquid flow, both in the wellbore and channels inside porous media or fractures, experiences more resistance compared to gas, resulting in significant pressure losses in the wellbore and fractures. Reservoir productivity also becomes more complex because of relative permeability effects. Forecasting production and estimating shale reserves is still not fully understood because of the limited knowledge of flow mechanics in ultralow-permeability rock.
Many analytical, semi-analytical, and numerical models have been developed to better understand flow in ultralow-permeability rocks and hydraulic fractures. Because analytical models only apply to mostly dry gas reservoirs, numerical reservoir simulation is generally believed to be the most rigorous and accurate method for liquid-rich formations. However, the drawbacks of using reservoir simulation are substantial. Some examples include the significant data requirements, level of expertise required to set up the model, and the demanding turnaround times for meeting the design, optimization, and decision-making cycle deadlines. Also, because each engineer is responsible for a large number of wells, full-scale three-dimensional (3D) reservoir modeling is impossible for a majority of wells.
Therefore, an approach is required that is less time-consuming than detailed reservoir simulation while still being sufficiently accurate to capture the physics of the process. It should be based on numerical modeling of multiphase flow in the interconnecting system of the wellbore and fractures, with the reservoir represented by a productivity index (PI) inflow model, as well as a physics-based pressure-volume-temperature (PVT) model for phase transition and phase equilibrium. The production decline and prediction should be analyzed based on reservoir depletion, relative permeabilities, and fracture conductivities.
This paper describes a numerical fracture production model (FPM) based on the previously mentioned physics that can be used to simulate production resulting from reservoir depletion and analyze historical production data. The outcome of the model focuses on a few primary input parameters that are dedicated to predicting future production and quickly analyzing the parametric effects and economic value of fracture-stimulated condensate reservoirs. The model is validated using two commercially available software programs, as well as historical production data of an Eagle Ford play. The outputs are then used for history matching, sensitivity analysis, parameter optimization, and future production prediction.
Yurchenko, Inessa (Stanford University) | Graham, Stephan A. (Stanford University) | Scheirer, Allegra Hosford (Stanford University and Geomodeling Solutions LLC) | Al Ibrahim, Mustafa (Stanford University)
Organic-rich sediments are deposited over a wide range of depositional environments. Understanding what controls the environment of deposition may help to predict the distribution of source rock properties. Numerous studies are devoted to understanding the factors controlling productivity and preservation of organic matter, such as anoxia, sedimentation rates, amount of nutrients, and type of organic macerals (Demaison and Moore, 1980; Pedersen and Calvert, 1990). Although many similarities exist in source rocks, many important differences also occur that might be used to differentiate them.
The Middle to Upper Triassic Shublik Formation is one of the key source rocks for hydrocarbons in Arctic Alaska and the greater Prudhoe Bay field area, one of the largest fields in North America (Bird and Molenaar, 1987; Magoon and Bird, 1985; Bird, 1994). It is a laterally and vertically heterogeneous unit that has been described both in outcrop and in the subsurface, and interpreted to have been deposited under fluctuating oceanic upwelling conditions (Parrish, 1987; Kupecz, 1995; Parrish et al., 2001). Modern upwelling zones are mainly associated with western sides of continents in low- to intermediate latitudes, where nutrient-rich waters result in high productivity, and are considered to be the most productive ecosystems in the ocean (Capone and Hutchins, 2013). Consistent with a coastal upwelling zone deposition interpretation (Parrish et al., 2001), the Shublik Formation is characterized by calcareous, glauconitic, phosphatic, and organic-rich lithofacies that reflect the chemical environment of Shublik deposition, suggesting that their major element and trace metal composition could be used as a proxy for paleoredox and paleoproductivity.
This study focuses on chemostratigraphic analysis of three Shublik cores using hand-held XRF data as elemental proxies for environment of deposition. The two most distant cores are 65 miles apart, and represent proximal and distal end-members. In addition to analysis of individual major and trace elements (over 20 elements) and elemental ratios (e.g. Si/Al, Si/Ti), a hierarchical cluster analysis has been applied to produce chemofacies. Combining chemofacies with biomarker paleoredox proxies, lithological description of the cores, and stochastic electrofacies analysis of well logs provides a highly-detailed, core-based understanding of the Shublik source rock environment of deposition.
Four thousand (4000) feet of core in Forty-one (41) wells, six (6) Maximum Flooding Surfaces (MFS), nannofossils and foraminiferal abundance peaks and marker species, 800+ TOC/%CO3 values were used to evaluate and correlate the Eagle Ford South Texas, Eaglebine in East Texas and Tuscaloosa in Louisiana-Mississippi. Interpretation of high resolution biostratigraphy, and well-log sequence stratigraphic analysis identified six (6) third order Galloway type sequences and maximum flooding surfaces (MFS) in all project wells from Webb county in South Texas to Wilkinson County Mississippi were used to demonstrate the time correlation of rocks of Eagle Ford age of different facies from East to West. It is especially important to correlate to the Tuscaloosa TMS because it is an emerging play and a new oil reservoir in Mississippi and Louisiana.
In order to understand the complex relationship vertically and laterally of the Eagle Ford, Eaglebine and Tuscaloosa calcareous nannofossils and foraminiferal high resolution biostratigraphic analysis, TOC/%CO3 and Maximum Flooding Surface sequence stratigraphic analysis were completed on the project wells. The depth of the high value intervals of TOC per well is proposed as a minimum depth for placement of the landing point for lateral wells.
Genetic Sequences range from Cenomanian 3 (Ce3) (96.01Ma) Sequence Boundary at top of Buda, to the Turonian 4 (Tu4) (87.88Ma) MFS in lower Austin. The Maness in South and East Texas basin, and Tuscaloosa in South Louisiana and Mississippi is characterized by Ce3 (95.69Ma) MFS. The Cenomanian Eagle Ford South Texas, Pepper shale in lower Woodbine Group East Texas Basin and the TMS in lower Tuscaloosa, are characterized by Ce4 (94.75Ma) and Ce5 (93.13Ma) MFS followed by a major unconformity at the Cenomanian–Turonian Boundary. The Turonian Eagle Ford South Texas, Eagle Ford Group (Upper Eaglebine) East Texas Basin and upper Tuscaloosa South Louisiana and Mississippi are characterized by the Tu1 (91.41Ma) to Tu4 (88.77Ma) MFS.
Landing zone selection is one of the key decisions for a subsurface team in order to improve productivity and profitability in unconventional plays. The optimal position depends on a combination of parameters including petrophysical and geomechanical properties, presence of natural fractures, and the stratigraphic architecture of the reservoir.
The Vaca Muerta Formation shows a high degree of vertical heterogeneity associated to the presence of argillaceous and calcitized ash beds, concretions, calcite veins, bindstone and other limestone beds. This heterogeneity controls the mechanical behavior of the succession affecting fracture efficiency. As a result, understanding the detailed stratigraphic architecture of the reservoir is relevant for landing zone selection. This work focuses on characterizing and predicting the heterogeneity of the Vaca Muerta reservoir associated to the stacking pattern of facies and their influence in ranking landing zones.
In the last five years the Upper Jurassic-Lower Cretaceous Vaca Muerta Formation (Neuquén Basin, Argentina) has awakened international interest due to its enormous potential as an unconventional oil and gas reservoir (Figure 1).
The Vaca Muerta Formation consists primarily of a mixed, carbonate-siliciclastic, outer ramp and basinal facies in the largely progradational, shallowing-upward Quintuco-Vaca Muerta depositional system. The geometry of the system is characterized by the development of diverse clinoform geometries (Gulisano et al., 1984, Mitchum and Uliana, 1985; Massaferro et al., 2014; Reijenstein et al., 2014; Sattler et al., 2016; González et al., 2016) (Figure 2). The organic-rich strata within the Vaca Muerta Formation reach up to 350 meters and display significant vertical and lateral heterogeneity.
Sedimentological and sequence stratigraphic studies provide the geological framework for understanding the genetic relation between the depositional system, textural changes, mineralogy, TOC and diagenetic processes. All these attributes affect reservoir quality and have an impact on drilling efficiency and completion quality.
The objective of this contribution is to emphasize the importance of detailed reservoir characterization in the exploration and development of unconventional plays for landing zone selection and ranking. In particular, this work shows advances in the sedimentological and stratigraphic characterization of the Vaca Muerta Formation conducted on core at different scales of analysis.
Putra, Rieza R. (Pukesmigas Trisakti University) | Larasati, Dian (NEGT Pertamina Upstream Technology Center) | Ardi, Sunarli (NEGT Pertamina Upstream Technology Center) | Fiqih, Fikri Muhammad (Pertamina Hulu Energi) | Ramdani, Hilman (Pertamina Hulu Energi) | Widarto, Djedi (NEGT Pertamina Upstream Technology Center) | Guntoro, Agus (Pukesmigas Trisakti University) | Usman, Alfian (NEGT Pertamina Upstream Technology Center)
Integrated from regional studies, geomechanical test from WCBF outcrop sample, conducted to determine where exactly placement of effective coal cleat accumulation. However, this paper focusly on structural and geomechanical aspect and which deformation phase that causing effective cleat accumulation.
Macroscale approach based on three stopsite of WCBF obtained major of west-east trending face cleat and north-south trending of butt cleat. The major trend of coal cleat respectively correlate with regional west-east shortening deformation phase due to tectonic inversion by Meratus Mountain during pliocene-pleistocene. Number of permeability value based on macroscale technique using outcrop matchsticks and cubes formula run widely in 7-46 darcy interval. Mesoscale approach using FMI analysis shows similar west-east coal cleat in subsurface (Coal Zone A) and strongly correlate with downward coal zone (B and C). Permeability value of mesoscale technique at 7.05 md and 5.2% of porosity based on CT Scan analysis from WCBF outcrop sample (TJ-11). The value of mesoscale permeability shows good negative exponential relationship through subsurface permeability test using IFO Test from 414-616 m of depth with range of permeability 3.3-0.23 md. Microscale measurement using SEM analysis from TJ-09, TJ-10, TJ-11 have values range from 0.6, 18.53, 17.824 md. As tested by mesoscale permeability integrated to IFO Test, each of approximation parameter would be respectively following the mesoscale exponential power law.
Geomechanic test was directly tested to SPL-03 sample from WCBF shows number elastic moduli; Young Modulus at 2652.74 MPa, Bulk Modulus 1163.48, Poisson Ratio 1069.65. Hydrostatic crossplot between depth against pressure (confining pressure from uniaxial test) clearly shows that overburden stress (SV) have no influence to create effective stress-driven cleat prior to deformation (Shmax and Shmin).
Fault Facies gave a brief classification of the area surrounding the fault which accomodate most effective cleat abundance in damage zone of the fault. Using weight factoring correlation between paleogeographic and strain partitioning by observe the geometry changing between bisected σ1 and σ3 trajectories. The most effective types of cleat occurs in distributed conduit and combine conduit barrier fault area with tensional-rotational and contractional-rotational strain region.
Altamont-Bluebell field is located in northeastern Utah within the Uinta basin. The Uinta basin is an asymmetric east-west trending basin with a south flank that has a gentle slope. The north flank is steep and bounded by east-west trending Uinta Mountains. The field is located in the northern-central part of the basin. In 2010, a 3D surface seismic survey was acquired over 35 square miles area within Bluebell Field, the eastern portion of Altamont-Bluebell field. The Bluebell field is considered an unconventional reservoir in the sense that natural fractures act as fluid storage and conduits in the tight sandstones, shales, and carbonates. Information related to fracture orientation and intensity is vital for the development of such reservoirs. Azimuthal variations of P-wave velocities can be a valuable tool for information related to fractures. Therefore, this paper utilizes Velocity Variations with Azimuth (VVAZ) to estimate the direction and intensity of fracture-induced anisotropy within Upper Green River formation. Upper Green River formation is the shallowest reservoir of the three main Tertiary reservoirs which includes Lower Green River and Wasatch/Colton formations.
A method for VVAZ inversion, based on the elliptical NMO equation for Transverse Isotropy (TI) media that was derived by Grechka and Tsvankin (1998), is applied. The method has been tested on a 3D physical modeling dataset. The results of the physical modeling test are found to be adequate (Al Dulaijan et. al., 2015). For Bluebell field 3D seismic data, isotropic velocities are used along with azimuthally variant time residuals to estimate fast and slow NMO velocities and their directions for the Upper Green River formation. Along with fast and slow NMO velocity maps, maps of fracture-induced anisotropy orientation and intensity were created. Pre-stack and post-stack seismic attributes are also calculated for the Upper Green River formation in Bluebell field and compared to VVAZ results. Intensity and orientation maps of seismic anisotropy are compared to post-stack coherency attributes and to geomechanical attributes obtained by seismic pre-stack elastic inversion to estimate brittle zones of the unconventional reservoir.
Yang, Jianzhong (Baker Hughes) | Szabo, Joseph (Baker Hughes) | Osgouei, Reza E. (Baker Hughes) | Arensdorf, Joseph (Baker Hughes) | Swartwout, Rosa (Baker Hughes) | Hartmann, Andreas (Baker Hughes) | Morris, Stephen A. (Baker Hughes)
High-definition resistivity logging while drilling (LWD) imaging tools can offer real-time solutions for wellbore placement, detailed reservoir characterization, structural interpretation, and optimized wellbore integrity management while drilling in complex reservoirs. However, these tools have been traditionally limited to drilling with water-based muds (WBM) due to the innate conductivity of these drilling fluids. At the same time, many operators prefer the use of invert emulsion oil-based fluids, especially in complex lateral and reservoir sections, due to the invert emulsion fluids' inherent higher performance and ability to reduce operational risks. The combination of high-definition, real-time imaging and oil-based drilling fluids in unconventional reservoirs can drive well efficiency with ideal fracture placements while retaining optimum drilling performance. Thus, an electrically conductive oil-based mud (OBM) has been a goal sought after by the drilling fluid industry for the past twenty-five years.
This paper will report the successful development of an invert emulsion drilling fluid that enables real-time resistivity imaging. The properties of the electrically conductive OBM and its response to a low-frequency resistivity imaging tool will also be discussed. Recorded images captured on a multi-layer sandstone formation with real-time, LWD technology will be presented with data interpretation.
The oil and gas industry is under increasing pressure to reduce the production cost per barrel of oil equivalent, especially for the unconventional sector. There is a renewed interest in technology to effectively improve drilling efficiency and reduce operating cost to help the shale sector remain profitable.
A general rule for the shale sector is that one-third of wells are not economical, one-third are marginally economical, and one-third carry the economics for the whole project.1 The major reason why two-thirds of all wells are marginal to non-profitable investments is the common practice of placing fracturing stages at regular intervals in a well with only limited information to evaluate the zones of productivity.
Urban, Edgar (University of Calgary) | Orozco, Daniel (University of Calgary) | Fragoso, Alfonso (University of Calgary) | Selvan, Karthik (Nexen Energy ULC) | Aguilera, Roberto (University of Calgary)
Multi-stage hydraulic fracturing (HF) of horizontal wells is at the heart of successful oil and gas production performance from tight and shale reservoirs.
Fractures generated during the initial HF completion and natural fractures, tend to close as a well goes on production due to the increase of net stress on the fractures. The fractures closure reduces permeability and consequently productivity of the stimulated well. This study shows that under favorable conditions the production performance of the well can be revitalized with the use of a refracturing job. But there are key questions that need to be addressed: (1) When is the optimum time for refracturing? (2) What is the increase in permeability, production rate and cumulative production performance that can be expected from the refracturing job? (3) Is it better to refracture the well or to drill an infill well?
This paper addresses those three questions by considering multi-porosities known to exist in shale reservoirs. This includes inorganic matrix porosity (ϕm), natural fractures (microfractures and slot porosity, ϕ2), organic porosity (ϕorg) and adsorbed porosity (ϕads_c). In addition, hydraulic fracturing generates porosity around the wellbore (ϕhf). These porosities form a quintuple porosity system that is further fed by gas dissolved in solid kerogen.
The porosities mentioned above are included in a material balance that is combined with fracture closure for generating a model that calculates the optimum time for refracturing. Production rates and ultimate recoveries from this model and observations of actual refracturing jobs are compared with results from infill drilling. By considering the same reservoir properties and exactly the same hydrocarbons in place the conclusion is reached that refracturing has the potential to be more cost effective as compared with infill drilling.
The novelty of the approach is the development of an easy to use production performance method that can be reproduced readily in a spread sheet for calculating optimum re-fracturing time, production rates, and cumulative recovery; and for making quick comparisons of the benefits of refracturing vs. infill drilling in shale reservoirs. Results of the easy to use material balance are corroborated with a state of the art commercial reservoir simulator.
Melick, J. J. (BP America Production Company) | Bulling, Thomas P. (BP America Production Company) | Koch, Jesse (BP America Production Company) | Thomas, Simon (BP America Production Company) | Diehr, Ted (BP America Production Company) | Davison, Frederick (BP America Production Company)
Mudstone resource plays have become a focus of industry activity over the last decade. Understanding the depositional limits of the play fairway can increase the probability of locating the sweetspot of the play. This paper outlines the importance of distinguishing a suite of mudstone sedimentary facies within high-resolution stratigraphy to define the vertical and lateral extents of source rock related to depositional environment. We examined cores containing mudstone and carbonate successions of the Trenton, Lexington, Pt. Pleasant, and Utica Formations deposited on an Ordovician platform sub-basin of eastern Ohio. The wells are located updip of the Rome Trough (i.e., Appalachian Basin to the east) in the Pt. Pleasant sub-basin associated with the Trenton carbonate platform.
Combining classical carbonate and siliciclastic core description techniques permitted the identification of five subtidal and seven deep-water carbonate facies associated with the unconventional mudstone play fairway. Petrophysical work from multiple cores, including SEM and thin-section analysis, identified a dramatic decrease in carbonate content and increase in argillaceous clay content upward across the Lexington - Pt. Pleasant contact. Stable isotope analyses (δ13C) of these cores also helped to deconvolve key stratigraphic intervals in the overall succession.
Detailed regional stratigraphic correlation and mapping of the Lexington and Pt. Pleasant Formations document apparently compensating southward-shifting intraplatform “sub-basins.” However, core analyses indicate that the underlying Lexington contains rippled mudstone that passes southward into suspension-dominated mudstone and bioclast gravity flow deposits. This is associated with a thicker slope environment thinning southward onto a platform, and not the fill of a sub-basin.
The Pt. Pleasant thickens southward and facies transition from an overall lower proportion of bioclast gravity flow deposits and rippled mudstone into high TOC suspension mudstones comprising the fill of an anoxic sub-basin and the “sweet spot.” Furthermore, a conspicuous erosional surface identified in the Miller-1 core of NE Trumbull County marks the pinchout of the Pt. Pleasant, which correlates with a significant δ13C isotope excursion (~2 per mil) seen in regional outcrop examples suggesting possible meteoric diagenesis and subaerial exposure. These relationships help to further distinguish the genetic relationship with the underlying Lexington.
This work demonstrates the importance of integrating log, core, and geochemical data to build a sequence stratigraphic view of the depositional history. Incorporating these data into the construction of a depositional model for the basin along with isopach maps of high-resolution sequences is critical in identifying the “play fairway” for access. Validation of the work is seen by plotting the IP rates and EUR bubbles on top of the play fairway. The actual Pt. Pleasant sweetspot, defined here as the area within the play fairway with the best rate of return, is further south in the play fairway than the overall depositional thick seen by mapping the Lexington and Pt. Pleasant interval.
This is a case study showing how vertical and lateral measurements in multiple horizontal wellbores in the Eagle Ford when integrated into hydraulic fracture models can be used to change the completion and frac designs to achieve significantly better production results.
An integrated study was conducted using Petrophysical and Geomechanical measurements from vertical pilot-hole logs and lateral logs. Reservoir characterization showed different properties in several type of Eagle Ford shale strata, Austin Chalk and Buda. Reservoir properties and mechanical properties such as porosity, total organic content (TOC), clay volume, Young's Modulus, Poisson Ratio and minimum in situ stress were calculated to aid drilling and completion practices. These properties were used to optimize the landing point within the Eagle Ford section and steer the well in the intended zone. Reservoir and sonic properties were utilized in perforation selection for the engineered completion design. Hydraulic fracturing model was run to optimize frac design. Post hydraulic fracturing data along with production log evaluations were utilized to continuously improve completion design.
Log data along with local geological model were used to identify faults and facies change in the lateral. Perforation depths were grouped based on relatively similar reservoir quality and low stress contrast. Hydraulic fracturing model results such as propped frac length and fluid efficiency were used to optimize pump schedule. Post hydraulic fracturing data evaluation and production logs were used to determine the optimum gross stage interval.
An aggressive pump schedule helped increase the production of the wells as they performed better than their peers. Production log data gave the distribution of hydrocarbon along the lateral and cluster efficiency. These parameters were key in optimizing stage and perforation design. The logs also confirmed reservoir analysis in stages to be bypassed resulting in stimulation savings and better overall well economics.
The wells that utilized this optimization process are top performers in their respective fields. In Area 1 the engineered completed wells are performing 40% better in average than all offset wells based on 90 day of oil cum per 1000 ft of lateral length. In Area 2 average production of engineered completed wells were 86% better than offset wells based on 90 day BOE cum per 1000 ft of lateral length.
This study will help the industry understand the use and benefit of vertical pilot and horizontal logs in optimizing landing points and completion designs in the Eagle Ford. Integrated measurements defining reservoir quality and completion quality of the strata are then used to design fracture treatments to deal with the properties found in the strata.