Sommacal, Silvano (FEI Oil and Gas) | Fogden, Andrew (FEI Oil and Gas) | Young, Benjamin (FEI Oil and Gas) | Noel, William (FEI Oil and Gas) | Arena, Alessio (FEI Oil and Gas) | Salazar, Leonardo (FEI Oil and Gas) | Gerwig, Tobias (FEI Oil and Gas) | Cheng, Qianhao (Australian National University) | Kingston, Andrew (Australian National University) | Marchal, Denis (Petrobras Argentina S.A.) | Perez Mazas, Ana Maria (Petrobras Argentina S.A.) | Naides, Claudio Hugo (Petrobras Argentina S.A.) | Kohler, Guillermina (Petrobras Argentina S.A.) | Cagnolatti, Marcelo (Petrobras Argentina S.A.)
Current understanding of hydrocarbon storage and flow in the matrix and fractures of shales is insufficient to predict recovery. Multiscale imaging of shale pore networks is foundational to multiscale modeling of transport for comparison to experimental measurements. The current study illustrates a workflow for integrated 3D imaging, analysis and property prediction using shale subsamples from the Vaca Muerta formation, Neuquén Basin, Argentina.
From a sample piece rich in organic matter (OM), three small horizontal plugs of 4 or 5 mm diameter were cored. Each of these sister plugs was micro-CT scanned in a sequence of prepared states, after which the tomograms were spatially registered into alignment. In particular, the plugs were scanned after solvent cleaning and drying, followed by a second scan after full saturation of their connected pore space with the X-ray dense liquid diiodomethane (CH2I2). The tomogram difference yielded a 3D volumetric map of total effective porosity at each voxel, despite the fact that the vast majority of pores lie below tomogram resolution. Each plug was then exposed to free iodine (I2), which stains OM to selectively increase its X-ray attenuation. The third scan in this iodine-stained state thus provided a registered 3D volumetric map of the OM distribution. Following these non-destructive steps, the plugs were sectioned and ion milled for high resolution BSEM imaging and SEM-EDS mineral mapping. These 2D mosaic images were registered into their corresponding cross-section through the plug tomograms.
To supplement this workflow, one of the plugs was first imaged in its uncleaned state in which the in-place oil was selectively X-ray contrasted to reveal its plug-scale 3D distribution, prior to cleaning. Another of the plugs, after micro-CT scanning of its CH2I2-saturated state, was drained in air by centrifugation and re-scanned, to yield the distribution of drained pores down to throat sizes of 20 nm. These analyses showed that the larger throats were most frequently hosted by OM, in the form of expulsion cracks, and that the majority of the oil resided in the OM.
Interest in re-stimulation of unconventional horizontal wells has continuously grown as operators and service companies recognize the existing opportunities to improve well productivity and recovery through refracturing operations. In response to this interest and to address the many challenges associated with this type of treatment, five operators in the Eagle Ford and one service company joined efforts in a Refracturing Consortium. Accelerating the learning while identifying the drivers for re-stimulation economic success were the main goals of the consortium
The project focused on testing various re-frac designs around recently developed diversion techniques to determine the best refracturing practices. A systematic candidate evaluation and re-stimulation design workflow was developed. Real-time monitoring was used to facilitate appropriate design modifications. Comprehensive evaluation was performed to determine the success factors.
Refracturing treatments were performed on 11 wells located across the field with varying completion and production characteristics. The production results are encouraging: uplifted production was attained from the majority of these wells and for a good number of treatments the increased production has been sustained over time. Incremental production six months after the treatments has averaged 25 Mbbls above what was expected in these wells without intervention.
This paper presents the production results from the campaign and discusses the success factors and main lessons learned such as:
The phase behavior of hydrocarbon fluids in nanoporous shales has become a very active research topic because of its large impact on hydrocarbon density and commensurate effects on reserve estimates and fluid mobility in shale gas production. The hydrocarbon density is complicated by the fluid-pore-wall interactions, pore-size distributions (PSD), surface chemistry, fluid composition, and other factors. When the fluids are stored in nanoporous media, strong attractions between the fluid molecules and the pore walls alters the fluid physical properties. The fluid molecules that occupy a small region close to the pore-wall area are adsorbed. Further, under favorable conditions, capillary condensation occurs; hydrocarbons have liquid-like properties in the pore throats and/or pores. Consequently, hydrocarbon-in-place is much larger in the presence of capillary condensation. In addition, capillary condensation in nanopore throats and/or small pores can block gas flow between pores and alter matrix transport.
We investigated the phase behavior of confined hydrocarbons, including both adsorption and capillary condensation, using the Simplified-Local-Density (SLD) method combined with the modified Young-Laplace equation. We apply the methodology to calculate the fluid content for different pore sizes and temperatures. To our knowledge, it is the first attempt to quantitatively consider both adsorption and capillary condensation for hydrocarbon mixtures in shale media and several important results have been obtained:
Zhang, Kai (University of Calgary) | Dong, Xiaohu (University of Calgary) | Li, Jing (China University of Petroleum) | Lv, Jiateng (University of Calgary) | Wu, Keliu (University of Calgary) | Kusalik, Peter (University of Calgary) | Chen, Zhangxin (University of Calgary)
A pore size is generally very small in tight oil reservoirs. It is 30 nm to 2,000 nm in diameter for tight sandstone reservoirs and 2 nm to 50 nm in diameter for shale reservoirs. In a confined system, the interaction between molecules and pore wall surfaces can alter the hydrocarbon thermal-dynamic properties, resulting in a variation in phase equilibrium. It has been recorded in previous research work. However, there is no clear statement for the reason of the confinement effect on phase equilibrium, and the minimum pore size at which the confinement effect is strong but meaningless is not recorded.
In this paper, multi-component phase equilibrium with the confinement effect is investigated, and the enthalpy and fugacity are recorded. Furthermore, molecular dynamic simulation is performed to study the flow of molecules inside nanopores and the energy is recorded. It can be seen that the effect of confinement contributes to a higher enthalpy in a mixture, which helps to keep a single phase fluid, so the vapor fraction for the fluid can be reduced. Also, the effect of confinement drives a reduction in the fugacity of light components and an increment of heavier components, which makes the vapor and liquid phase equilibrium composition become closer to each other. The critical size for molecules to flow through nanopores is two times the biggest molecular diameter. The confinement effect works until a pore diameter is within 5 nm, and it is extremely difficult for the heaviest hydrocarbon component to move out of pores with a diameter less than 5 nm.
Tight oil resources contribute to a tremendous crude supply in recent years.1 Its primary recovery still remains low even with the advanced technology in hydraulic fracturing and horizontal wells.2 Furthermore, the production characterization of tight oil reservoirs is quite different from the conventional one.3 Recent studies have mainly focused on the fluid phase behavior in tight reservoirs.4-12
Basin uplift/exhumation periods have tremendous implications in term of unconventional plays productivity. These events may indeed lead to an increased permeability, and enable to drill overpressure formations at shallower depths. Such event may also damage the formations to an extent that any preexisting overpressure cannot be preserved. As a consequence, characterizing early-on the basin uplift is critical to understand play productivity.
Uplift magnitude was assessed in the Utica play in the Appalachian basin. A combination of two methods was applied. The first is a basin modeling approach combining a tectonic calendar and geochemical data. The second uses shale compaction based on the measurement of the mismatch between observed and theoretical sonic porosity. Merging the methods allowed honoring the basin history while increasing the granularity within the zone of interest.
The resulting uplift magnitude map, paired with maturity trends, provides a zonation of the Utica play expected performance that correlates with actual wells performance.
This case study shows that characterizing uplift intensity and maturity trends across a play can be powerful to delineate early on the most productive areas.
Early delineation and zonation of unconventional play is a critical step for optimizing acreage acquisition. The exercise is however challenging because of limited data available, which consist generally of legacy wells and few pilot wells. In this work, we propose an approach based on the characterization, from standard sonic logs, of differential uplift intensity in the basin. The impact of uplift intensity in unconventional play productivity is explained in the first part of the paper. The characterization methodology is subsequently explained. In the last part of the paper, the methodology is applied to the Utica play in the Appalachian basin.
Uplift and Productivity in Unconventional Plays
Sedimentary basins have complex tectonic histories with periods of burial, in which sedimentation and source rock maturation occur, along with periods of uplift in which orogeny and erosion happen. Both burial and uplift alter reservoir pressure.
A relatively new technology, multilateral horizontal completions, has made shale oil and gas plays economical targets for unconventional exploration and production endeavors. Law and Curtis (2002) defined unconventional plays as those that target reservoirs with low porosity or permeability. The subsurface “lower” Eagle Ford formation, which corresponds to the middle member in outcrops around the Del Rio, Texas area (Lock and Peschier, 2006), is a focus of exploration and production efforts. Outcrops of the middle member have therefore been the subject of rigorous studies to determine the long-term production potential of the “lower” Eagle Ford. Two primary researchers, Dr. Brian Lock (University of Louisiana at Lafayette) and Dr. Art Donovan (BP), have independently investigated outcrops of the formation near the Del Rio area including Lozier Canyon. These investigations have resulted in multiple detailed works being published including those by Lock and Peschier (2006), Lock and others (2010), Donovan and Staerker (2010), Gardner and others (2013), and Lock (2014). These authors have conducted numerous geochemical studies of the Eagle Ford from both outcrop and core of the middle transgressive member, the member defined at its base by the first significant marine flooding surface of the sequence (Van Wagoner, et al., 1988). Little work, however, has been completed at the smaller scale bed and bed-set level to study minor variations within the parasequences. Variation in the geochemical framework and general heterogeneity of shales makes some intervals within shale “reservoirs” more productive than others. These variations are in response to changing conditions within the environment of deposition, and are revealed as changes in paleoenvironmental oxygen conditions, clastic influx, and paleoproductivity. Changes in these parameters can be used to identify subtle changes in the environment of deposition within parasequences.
The main goal of this thesis is to identify and therefore predict changes in the source rock potential and environment of deposition between beds within discrete parasequences in the middle member of the Eagle Ford formation at Lozier Canyon. If variations are present, implications for the prediction and identification of optimal horizontal drilling intervals will be hypothesized. The results of this study may also lead to the application of these techniques for other complex, organic-rich shale plays in the future.
Verma, Sumit (The University of Wyoming) | Zhao, Tao (The University of Oklahoma) | Marfurt, Kurt J. (The University of Oklahoma) | Devegowda, Deepak (The University of Oklahoma) | Grana, Dario (The University of Wyoming)
The Barnett Shale in the Fort Worth Basin is one of the most important resource plays in the USA. TOC and brittleness can help to characterize a resource play to assist in the search for sweet spots. Higher TOC or organic content are generally associated with hydrocarbon storage and with rocks that are ductile in nature. Brittle rocks, however, are more amenable to fracturing with the fractures faces more resistant to proppant embedment. Productive intervals within a resource play should therefore contain a judicious mix of organics and mineralogy that lends to hydraulic fracturing. Identification of these intervals through core acquisition and lab-based petrophysical measurements can be accurate but expensive in comparison to wireline logging. In this work, we estimate TOC from wireline logs using Passey's method and attain a correlation of 60%. However errors in the base line interpretation can lead to inaccurate estimates of TOC. Using non-linear regression with Passey's TOC, normalized stratigraphic height and acquired wireline logs the correlation was increased to 80%. This regression can be applied to uncored wells with logs to estimate TOC and thereby provides ground truth within the seismic survey. Core measurements provide relatively more accurate measures of both TOC and mineralogy. Brittleness index (BI) is computed based on mineralogy using Wang and Gale's formula. The correlation between this mineralogy based BI and BI estimated using elastic logs (λρ, μρ, VP/ VS, ZP and ZS) and wireline logs is 78%. However, this correlation decreases to 66 % if the BI is estimated using only wireline logs. Therefore, the later serves as a less reliable proxy. We correlate production to volumetric estimate of TOC and brittleness by computing distance weighted averages about assumed perforations in 120 horizontal wells. We obtained a production correlation of 38% on blind wells, which was encouragingly suggesting that the geologic component in completions provides an important contribution to well success.
Over the last decade an unconventional revolution has occurred through the use of horizontal drilling and hydraulic fracturing. Countless operators have invested billions to develop new resources and implement factory mode completions which have changed the landscape of the oil and gas industry. The impact of unconventional completions has led to a global market surplus of both oil and gas at the date of this publication. To succeed in today's market, operators must evolve by testing innovative methods to drill and complete unconventional developments with a focus on capital efficiency.
The most common completion method for shale horizontal wells is a cemented plug and perforation stage design. Although aspects of the plug and perforation design have been optimized to deliver improved well performance and operational efficiency, there is still an opportunity to maximize cluster efficiency and zonal isolation. One of the methods is creating pin point fractures through the use of coiled tubing cemented sleeves. The sleeves allow for single point injection and greater control of fracture initiation to maximize stimulated rock volume and reservoir drainage across the lateral.
While some in the industry have trialed the technology, few have focused on how to optimize the sleeve design in terms of fracture interaction and completion design. Linking the design of the sleeve technology to upfront modeling efforts can accelerate the application in unconventional plays. This paper will present the modeling aspects and surveillance to optimize shale completions through the use of coil tubing frac sleeves. Furthermore, operational aspects of this alternative completion method and various learnings that provide for future optimization will be discussed. Finally, field data will be used to illustrate the impact of the completion design.
This paper focuses on upfront modeling efforts, field implementation, and resulting analyses of a non-traditional type of completion technique — single point entry completion system. Plug and perf is the operator's completion method of choice and it is widely believed that achieving complete cluster efficiency is challenging using this method. In contrast, the single point entry completion system is expected to provide the technical limit for cluster efficiency.
A multifrac horizontal flowback program in shales must address several competing objectives. The desire for short-term and immediate high initial production (IP) rates must be balanced with the potential for damage to the proppant pack and near-wellbore region resulting from an aggressive drawdown strategy. To understand the potential for this damage, a series of geomechanical models were constructed to calculate the effective stress in the near-wellbore region that results when different drawdown scenarios are applied. The different drawdown scenarios used in the model were based on hourly bottomhole pressure declines that are typically observed in the field, ranging from 0.5 to 20 psi/hour. This model was constructed using core-derived mechanical properties and in-situ stress and pore pressure estimates from a calibrated dipole sonic log.
The study concluded that a drawdown of 1 to 5 psi/hour helps to significantly reduce the peak stress imposed on the proppant pack. Actual production performance has indicated that reasonably high production volumes are still achievable while maintaining these lower drawdown rates. Water handling volumes are also reduced significantly. The modeling was used to support a basin-wide drawdown management document to establish field production practices in the horizontal well program. Finally, a comparison of well performance resulting from various drawdown strategies is presented to support the development of best practices.
Flowback practices in unconventional reservoirs have been the subject of increasing interest to the industry in recent years (Jacobs 2015). Unconventional wells are often overpressured, which can lead to very high production rates and rapid drawdowns of flowing bottomhole pressure (FBHP). Due to the low permeability of the formation, high pressure gradients may develop near the wellbore which can lead to increased stress and fracture damage.
Additionally, the proliferation of electronic gauges with high data frequency has allowed real-time monitoring of well performance, providing the engineer with more flexibility in production optimization (Deen, Daal and Tucker 2015). There are many value drivers when designing a choke management strategy for unconventional reservoirs, several of which are summarized in Figure 1. A conservative drawdown strategy utilizes a smaller choke size to restrict flowing bottomhole pressure (FBHP) declines over the course of several months. A conservative strategy has several potential benefits including minimizing fracture damage, maintaining the reservoir pressure above saturation pressure for a longer period of time in order to maximize liquid recovery, and reducing the size of permanent facilities. Additionally, a conservative drawdown strategy can also mitigate sand production to protect surface facilities (Karantinos, et al. 2016). Conservative drawdown strategies are routinely utilized on wells in overpressured gas shales such as the Haynesville (Okouma Mangha, et al. 2011), Montney (White, Lavery and Rock 2014), and the deep Utica (Consol Energy 2016).
Mukherjee, S. K. (Oil and Natural Gas Corporation Limited) | Rao, S.C (Oil and Natural Gas Corporation Limited) | Guru, Rakesh (Oil and Natural Gas Corporation Limited) | Chitnis, S.N. (Oil and Natural Gas Corporation Limited) | Ray, B. B. (Oil and Natural Gas Corporation Limited)
With a significant number of wells drilled and proven to be hydrocarbon bearing in basement, Mumbai High field in Western Offshore, India is one of the priority areas to prove and extend the concept of basement hydrocarbon accumulations. It has been observed that basement in Mumbai high is hydrocarbon bearing wherever major regional tectonic cross trends are observed. The real challenge of delineating Mumbai High basement reservoir lies in the uniqueness of fracture connectivity which is again related to basement lithology, prevailing stress fields and the density, aperture and length of fractures.This paper describes a methodology for characterizing basement reservoir by adopting a synergistic technique involving geological concepts, well data and geocellular modeling. The model thus prepared calibrates well with hydrocarbon accumulation pattern in basement wells tested in the area and has been of immense help in planning exploratory wells as well as exploiting reserves of the field.
The western continental shelf margin of India is an Atlantic type margin featured by longitudinal extensional faults in parallel sets giving rise to a series of narrow horst and graben structures. The style of faulting is controlled by three major orogenic trends in the western part of the Indian shield: NE-SW Aravalli, ENE-WSW Satpura, and NNW-SSE Dharwar trends (Biswas S.K., 1982). The tectonic elements defining basement architecture of Mumbai High are in agreement with these regional tectonic grains (figure1).
Analyses of FMI logs of basement interval drilled in the area have helped decipher the principal stress direction (SHmax)as NNW-SSE (Dharwar trend) which is validated by borehole breakout studies and seismic attributes (figure 2).
The present study has made an attempt to create a robust fracture intensity model combining seismic attributes with petrophysical, geomechanical and geological inputs. Calibrations and validations of the fracture model thus generated have been carried out using well data where available.