Actually, the definition of a tight gas reservoir is a function of many factors, each relating to Darcy's law. The main problem with tight gas reservoirs is that they do not produce at economic flow rates unless they are stimulated--normally by a large hydraulic fracture treatment. Eq. 7.1 illustrates the main factors controlling flow rate.
Tight gas reservoirs generate many difficult problems for geologists, engineers, and managers. Cumulative gas recovery (thus income) per well is limited because of low gas flow rates and low recovery efficiencies when compared to most high permeability wells. To make a marginal well into a commercial well, the engineer must increase the recovery efficiency by using optimal completion techniques and decrease the costs required to drill, complete, stimulate, and operate a tight gas well. To minimize the costs of drilling and completion, many managers want to reduce the amount of money spent to log wells and totally eliminate money spent on extras such as well testing. However, in these low-permeability layered systems, the engineers and geologists often need more data than is required to analyze high permeability reservoirs.
The most reliable way to determine stress orientation is to identify features (either geological features or wellbore failures) the orientation of which is controlled by the orientations of the present-day in-situ stresses. Other methods that rely on observing the effect of stress on rock properties using oriented core have been found to be less reliable and subject to influence by factors other than in-situ stress. As previously discussed, wellbore breakouts occur in vertical wells at the azimuth of SHmin, and drilling-induced tensile failures occur 90 to breakouts at the azimuth of SHmax. Therefore, the orientations of these stress-induced wellbore failures uniquely define the orientations of the far-field horizontal stresses when using data from vertical wells. This is true for breakouts whether they are detected using 4-arm- or 6-arm-oriented caliper logs or using electrical or acoustic images, whether obtained by wireline or logging while drilling (LWD) tools.
Frac fluid delivery is selective in effect, so must fracture models. Here, a physics-based analytical model, called nine-grain model, is presented for production forecasting in multifrac horizontal wells in unconventional reservoirs, where the utilized formulation inherently enables defining three-dimensional non-uniform SRVs, selective frac-hits, and pressure- and time-dependent permeabilities. The model is validated by constructing case studies of liquid and gas reservoirs and comparing the results with numerical simulations. In cases with both production history and fracing-induced microseismic data available, the SRV's spatial structure is extracted using a hybrid four-level straight-line technique that links volumetric RTA estimations to morphometric microseismic analysis and entails plots of plasticity, diffusivity, flowing material balance and early linear flow. By applying our model to an oil well in Permian Basin, we demonstrate that the knowledge gained from the coupled microseismic-RTA contributes to resolving the non-uniqueness of RTA solutions. The proposed reservoir modeling procedure enables efficient incorporation of microseismic interpretations in modern RTA while honoring the SRV space-time variability, thus facilitates informed decision making in spacing design of wells and perforation clusters.
Frac-hits. A frac-hit can be defined as observing a perturbation in the well production rate and/or pressure that is induced by a child offset (or an infill) well, usually triggered by pressure sinks created around parent wells or high permeability lithofacies. A frac-hit that temporarily alters the parent well productivity is called a communication frac-hit, and those with long-term effects, generally caused by fracture interference, are referred as interference frac-hits. A frac-hit may also compromise the productivity of the child well itself since the existing pressure sinks distribute the fracing energy in a larger area and might lead to an asymmetric fracture growth around the child well. Besides the parent well operational condition, the microseismic monitoring of fracing can potentially indicate interference frac-hits as it reveals fracture overlaps and any preferential fracture dilation towards existing wells. Depending on the rock and fluid properties, well age, parent-child horizontal and vertical distances, and the spatial extent of Stimulated Reservoir Volume (SRV), the constructive (Esquivel and Blasingame 2017) or destructive (King et al. 2017, Ajani and Kelkar 2012) effects of frac-hits can be experienced by fractures, SRV or the entire drainage volume (stimulated and non-stimulated zones), usually by impacting rock multiphase fluid interfacial arrangements and/or changing dimensions of conductive fractures. Aside from prevention, thoroughly reviewed by Whitfield et al. (2018), it is essential to incorporate frac-hits into production forecasting models, which to date, is not yet as straightforward as their detection. Both types of frac-hits cause a change in the well productivity over time which is not necessarily correlated with pressure, and hence, complicate the reservoir modeling process.
Distributed vibration sensing has provided a new measurement technique for monitoring hydraulic fracture treatments. We demonstrate that successful existing approaches that integrate pumping parameters and microseismic observations with complex fracture simulation and 3D mechanical earth modelling can be extended to incorporate distributed strain, vibration and flow allocation providing a highly constrained interpretation.
In a monitoring well, where we deploy a hybrid borehole geophone array of 3C geophones for accurate microseismic events mapping, we additionally recover a signal related to static strain from the lowest vibration frequencies of the fibre. From this hybrid cable composed of fiber interconnects and 3C geophones, we may recover extended-aperture information (i) to supplement the geophone-acquired data at microseismic frequencies, (ii) to better constrain hypocenter determination and associated characteristics (e.g., source parameters, attributes, rock failure mechanisms). Furthermore, deploying a fiber within the treatment well, we can recover the relative flow split between the perforation clusters, obtain the bottom hole pressure using the attenuation of the pump harmonics, etc. We integrate these new measurements into the existing geomechanical modelling approach to stimulation interpretation.
We present an example of job planning where synthetic fiber vibrations at the full frequency range and pump data as well as geophone responses are created based on geomechanical and geophysical simulation.
The objective of our research is to reconcile the differences, in both age and relative stratigraphic position, between the Woodbine and Eagle Ford Groups in the outcrop and subsurface of the East Texas Basin. In the outcrop belt, organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Eagle Ford Group, where they overlie, and are separated by a regional unconformity from Early Cenomanian, organic-poor, and clay-rich mudstones of the Woodbine Group (Pepper Shale). In southern portions of the East Texas Basin, however, these same organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Maness Shale, which in turn, is overlain by Late Cenomanian to Turonian-aged mudstones (Pepper Shale) and sandstones (Dexter Formation) mapped as the Woodbine Group. Our approach to reconcile the lithostratigraphic juxtaposition between the two regions was to use chemo-stratigraphic and petrophysical data collected from the outcrops, as well as an adjacent shallow research borehole, in order to define key sequence stratigraphic units/surfaces, and then correlate the key units/surfaces from the outcrop belt into the subsurface.
Our research indicates that the Woodbine Group, is an older unconformity-bounded depositional sequence which is Early Cenomanian, whereas the Eagle Ford Group, is an overlying (younger) unconformity-bounded depositional sequence, which is Middle Cenomanian to Late Turonian. The unconformities that bound these units can be mapped from the outcrop belt into the subsurface of the East Texas Basin, to define coeval depositional sequences. As defined in this study, marine mudstones of the Woodbine Group, are clay- & silica-rich, TOC-poor, and characterized by low resistivity on geophysical logs. In general, the Woodbine Group thins, as well as transitions to more mudstone-prone facies, from northeast to southwest within the basin. While beyond the scope of this study, the Woodbine Group contains numerous higher-frequency sequences, which are stacked in an overall progradational (highstand) sequence set. The depositional profile of the unconformity which forms the top of this progradational succession sets up the relict physiographic (depositional shelf/slope/basin) profile for the overlying Eagle Ford Group.
Within the Lower Eagle Ford Formation, two high-frequency sequences, defined as the Lower and Upper Members, were defined. Within the Upper Eagle Ford Formation, three high-frequency sequences, defined as the Lower, Middle, and Upper Members, were defined. The Lower and Upper Members of the Lower Eagle Ford Formation, as well as the Lower Member of the Upper Eagle Ford Formation range from Middle Cenomanian to Early Turonian. These three high-frequency sequences contain marine mudstones that are carbonate- & TOC-rich, as well as clay- and quartz-poor, and are characterized by high resistivity values on geophysical logs. Furthermore, they are interpreted as a transgressive sequence set, with sequences that sequentially onlap, from older to younger, the inherited relict physiographic (depositional shelf/slope/basin) profile of the underlying Woodbine Group. In stark contrast, mudstones within the Middle and Upper Members of the Upper Eagle Ford Formation, which are Middle to Late Turonian, are clay-rich, TOC-poor, and characterized by low resistivity on geophysical logs. These two sequences, which are interpreted as a highstand sequence set, are sandstone-prone, and contain petroleum reservoirs that previously were incorrectly included within the Woodbine Group. Based on these correlations, updated sequence-based paleogeographic maps can be constructed for the first time across the East Texas Basin. These maps can in turn be used to define a robust portfolio of conventional, as well as unconventional tight-rock and source-rock, plays and play fairways, which are now based on a modern sequence stratigraphic, versus the traditional archaic lithostratigraphic framework.
The goal of our work was to maximize gas production and recovery from a horizontal appraisal well in the Mancos shale in New Mexico. This required a fracture design that would maximize perforation cluster efficiency and a lateral placement strategy that would maximize gas recovery. A key challenge was to design a fracture treatment that would overcome the extreme stress shadowing effects. Another key challenge was to optimize the lateral placement balancing multiple factors.
Fracture treatment simulations were completed for various designs. Fracture simulations indicated cluster efficiency could be dramatically improved by optimizing the way we pump the pad. A step-up technique for increasing pumping rates during the pad stage helped to initiate more fractures. Intra-stage diversion was utilized. Fracture simulations were performed to optimize the lateral placement. This required balancing multiple factors to access the highest gas-in-place (GIP) interval yet facilitate more fracture initiations per stage.
Fracture descriptions from the fracture simulations were input to a reservoir simulator to determine the optimal design. This paper will focus on the hydraulic fracture modeling.
This appraisal well was the most productive Mancos gas well ever delivered in the San Juan Basin. The 9,546’ lateral produced at a choke constrained plateau rate of about 13 MMscfd for 7 months and produced over 6 BCF in the first 20 months. A radioactive tracer log indicated an overall perforation cluster efficiency of 83%, a significant achievement in a shale with high stress shadowing.
The fracturing fluid design, diverter design and pumping techniques can be applied in many other shales as a low-cost way to increase perforation cluster efficiency, which will in turn result in higher production rates and higher cumulative recovery. Building on the success observed in the Mancos wells, BP and BPX Energy have subsequently utilized these techniques in other shale plays with success.
The concepts and workflow used to decide the optimal lateral placement is a well-defined approach that can be applied to other unconventional wells to increase hydrocarbon recovery.
Economic hydrocarbon production from organic rich shale has been made feasible by advances in horizontal drilling and hydraulic fracturing. Proppants are pumped to keep the fractures open and provide a high conductive path from the reservoir to the wellbore. Effects of proppant size, proppant crushing, fines migration, rock mineralogy and fluid chemistry on the long-term fracture conductivity have been studied experimentally in detail by Mittal (2017, 2018). This study further investigates the impact of proppant concentration, size and presence of different volcanic ashes on fracture conductivity along with different conductivity impairment mechanisms including proppant crushing, embedment and diagenesis under simulated reservoir conditions.
Experiments have been conducted by varying the proppant concentration of 60/100 mesh Ottawa sand from 2 lb/ft2 to 4 lb/ft2. The proppant pack was placed between metal platens and subjected to axial load of 5000 psi and temperature of 250 °F. Proppant pack conductivity was then measured by flowing 3% NaCl brine for periods of 7-15 days. We observed a sharp decline in permeability, with almost 98% decline within 3 days with low concentration compared to only 60% decline in permeability with higher concentration of proppant. Particle size analysis reveals overall 5% higher percentage crushing at lower proppant concentration, suggesting major crushing occurs at the platen interfaces which reduces with increased proppant pack concentration.
Presence of volcanics in the major shale plays like Eagle Ford and Vaca Muerta has been reported in literature. To simulate similar environment and study the impact of diagenesis on fracture conductivity, experiments have been conducted by flowing high pH (~10) brine through the proppant pack mixed with volcanics like obsidian and basalt and placing the proppant between Eagle Ford shale platens. Experiments were conducted with 20/40 Ottawa sand mixed with obsidian and 60/100 mesh Ottawa sand mixed with basalt. We observed a sharper decline in permeability with 60/100 sand as compared to 20/40 sand in the first two days. However, the permeability for both the proppant sizes continues to decline with a difference of an order of magnitude even after 30 days. SEM images shows significant particle crushing, embedment and diagenetic growth on the shale surface and verify that these factors are responsible for permeability decline. To further understand the impact of proppant size on permeability, dry crush tests have been conducted on 20/40 and 60/100 Ottawa sand by varying compaction pressure from 1500 psi to 3000 psi and 5000 psi. We observed that 60/100 mesh sand undergo overall higher compaction and crushing compared to 20/40 mesh sand at each compaction pressure.
As unconventional plays in North America mature, understanding the performance of step-out and infill wells becomes increasingly important. “Child” well performance has become a major topic of interest because in every unconventional play there exists a significant portion of child wells that perform worse than their “Parents”. It is important to understand how child wells are likely to perform across a play so that engineers can properly forecast production and organizations can allocate capital correctly. The objective of this study was to establish an efficient scoping workflow for understanding the effect of depletion on child well performance across an area of interest, so that promising infill locations can be recognized, and risky infill locations avoided.
The problem with the current parent-child paradigm is that it requires explicitly defining what constitutes a parent, or conversely a child. As described in this study, the choice of definition immediately introduces bias into the interpretation of child performance. A simple function was developed to express the parent child relationship as a continuum, where the influence of parents on a given reference well decays with distance. A workflow was then established to apply the function across a large public well dataset. The workflow handles stacked development, accommodates large scale geological variation and can be efficiently applied over a significant number of wells.
The workflow was applied to areas of interest within the Montney formation in the Western Canada Sedimentary Basin. Results indicate that the depletion function can describe well performance in many areas of interest. Child performance heat maps were generated to identify potential opportunities for infill development. The workflow was also employed to detect performance outliers which could be further investigated to understand child well optimization.
Recent studies have indicated that a substantial percentage of wells “Children” in unconventional plays perform worse on a completion-normalized basis than their predecessors within a defined distance “Parents” (Lindsay et al. 2018). One of the main reasons cited for poorer than expected performance of Child wells is depletion (Cao et al. 2017, Lindsay et al. 2018, Shin and Popovich 2017). Depletion in the vicinity of the child well has the following effects:
Tomassini, Federico Gonzalez (YPF SA) | Smith, Langhorne (Taury) (SmithStrata) | Rodriguez, Maria Gimena (YPF SA) | Kietzmann, Diego (University of Buenos Aires - CONICET) | Jausoro, Ignacio (YPF Tecnología SA [Y-TEC]) | Floridia, Maria Alejandra (YPF Tecnología SA [Y-TEC]) | Cipollone, Mariano (YPF Tecnología SA [Y-TEC]) | Caneiro, Alberto (YPF Tecnología SA [Y-TEC]) | Epele, Bernarda (YPF Tecnología SA [Y-TEC]) | Santillan, Nicolas (YPF Tecnología SA [Y-TEC]) | Medina, Federico (YPF Tecnología SA [Y-TEC]) | Sagasti, Guillermina (YPF SA)
The objective of this work is to present the pore types and their relationship to the main core facies from the Vaca Muerta Formation, Neuquén Basin, Argentina. With an in-house methodology for focused Ion Beam scanning electron microscope (SEM) images and petrographic analysis, a linked to increase the understanding of the pore systems, mineralogy, diagenetic features, grain types and facies variations is carried out. Long continuous cores from two wells were described in detail by standard facies analysis and SEM for semi-quantitatively estimating total porosity, relative abundance of pore types and pore sizes, mineralogy, relative abundance of kerogen and migrated bitumen, type and origin of different clays, and diagenetic quartz abundance among other features. The SEM porosity, organic matter content and mineral distribution correlates favorably with independent measurements obtained by other labs methods. The findings were linked to the core descriptions and the regional sequence stratigraphic framework to predict best reservoir facies. This prediction is done with the production results for each horizontal well in the different landing zones. Finally, the understanding of the pore system can be used to define the best areas and intervals where horizontal wells can be geosteered during the development stage of a block.
The Tithonian-Valanginian (Upper Jurassic-Lower Cretaceous) Vaca Muerta Formation is the main source rock of the Neuquén Basin (Figure 1). The Vaca Muerta Fm. is a lower slope and basinal facies equivalent to the updip Quintuco and Loma Montosa Formations. This formation is a very appealing target for unconventional development due to its vast lateral extent, great thickness (up to 500 m – 1640 ft), relatively high values of total organic carbon (TOC 2-10 %), thermal maturity (oil to dry gas windows), mineralogical composition (less than 30% clay), overpressure and relatively simple structural setting. The study area is located in the center of the Neuquén Basin (Figure 1), north of the Huincul high and mainly in the Añelo depocenter where major activity is taking place. More than 600 horizontal wells have been drilled in the basin in different landing zones resulting in different hydrocarbon production. The EIA (2013) estimated that the technically recoverable resources estimated for this formation are in the order of 300 Tcf of gas and 16 Bbbl of oil and these numbers may be low.