Brice Y. Kim and I. Yucel Akkutlu, Texas A&M University, and Vladimir Martysevich and Ronald G. Dusterhoft, Halliburton Summary The stress-dependent permeabilities of split shale core plugs from Eagle Ford, Bakken, and Barnett Formation samples are investigated in the presence of microproppants. An analytical permeability model is developed for the investigation, including the interactions between the fracture walls and monolayer microproppants under stress. The model is then used to analyze a series of pressure-pulsedecay measurements of the propped shale samples in the laboratory. The analysis provides the propped-fracture permeability of the samples and predicts a parameter related to the quality of the proppant areal distribution in the fracture. The proppant-placement quality can be used as a measure of success of the delivery of proppants into microfractures and to design stimulation experiments in the laboratory. Introduction Unconventional-oil/gas resources, such as tight gas/oil and resource shale, have low porosity and ultralow permeability. Creating a well-connected complex fracture network is a key component of increasing the permeability and accelerating production. The early era of hydraulic fracturing horizontal wells in unconventional formations was concerned with achieving long fractures with multistage treatments with large cluster spacing. However, recent trends in this type of well completion and stimulation involve fractures that are created in narrower clusters in much closer spacing, targeting larger surface areas. It is argued that the practice of hydraulic fracturing with narrow clusters in close spacing along a lateral wellbore creates fractures with significantly reduced sizes, but in a complex network (Rassenfoss 2017). The creation of a network of fractures includes major operational issues.
It was designed to reduce the completion or stimulation cost and time by placing multiple perforation clusters (typically three or more clusters per stage) and performing fracture stimulation by pumping the fluid/proppant system at very high rates to generate the necessary differential pressure and multiple fractures per stage. Because the stimulation pump rate in unconventional reservoirs is typically a function of the number of perforation clusters, number of perforations per cluster, the entry hole diameter of the perforations, and a fixed required minimum rate per perforation, the resulting typical pumping rates to perform fracture stimulations to generate more than one fracture per stage is in the range of 60 to 100 bbl/min or higher. However, historically, the fracture stimulation of multiple perforation clusters performed at high pumping rates often resulted in almost 80% completion efficiency as documented by Wheaton et al. (2016). Therefore, during each stage, single or multiple perforation clusters might not be fractured or marginally stimulated, and thus do not contribute to well production. The same system has been also used during refracturing operations or to increase the number of clusters per stage.
The key factor for characterizing unconventional shale reservoirs is the total organic carbon (TOC). TOC is estimated conventionally by analysis cores samples which requires extensive lab work, thus it is time-consuming and costly. Several empirical models are suggested to estimate the TOC indirectly using conventional well logs. These models assume the TOC and well logs are linearly related, this assumption significantly reduces the TOC estimation accuracy. In this work, the design parameters of the artificial neural network (ANN) were optimized using selfadaptive differential evolution (SaDE) method to effectively predict the TOC from the conventional well log data. A new correlation for TOC calculation was developed, which is based on the optimized SaDE-ANN model.
Yi, Sophie (The University of Texas at Austin, now with Pioneer Natural Resources) | Manchanda, Ripudaman (The University of Texas at Austin) | Sharma, Mukul (The University of Texas at Austin) | Roussel, Nicolas (ConocoPhillips)
Horizontal-well refracturing is important in the development of unconventional plays to improve the productivity of the refraced well and to protect parent wells from the fractures propagating from the nearby child wells. In the field, heel-biased fracture propagation is frequently observed in refracturing treatments, leaving a large fraction the wellbore understimulated. In this paper, we explain the mechanisms of heel-biased fracture propagation and suggest strategies to mitigate such behavior.
We model refracturing operations accounting for reservoir geomechanics, wellbore hydrodynamics, completion strategies, as well as near-wellbore effects. A coupled reservoir geomechanics simulator is used to calculate the poroelastic stress changes in the reservoir due to production. Then, a multi-fracture simulator with newly developed wellbore fluid and proppant transport model is applied to simulate the refracturing process. A field refrac case is simulated and the simulation results show good agreement with field diagnostics including proppant distribution among multiple fractures. The simulation results help us understand the mechanisms behind heel-biased fracture propagation in refractured wells and allow us to investigate strategies to improve refrac treatment efficiency.
The mechanisms affecting treatment distribution in refracs are investigated from two perspectives: the non-uniform pore pressure and stress profile in the reservoir, and the wellbore hydrodynamics. The latter perspective studies the fluid and proppant transport and separation in the wellbore. With the long wellbore length and the large number of open fractures, the impact of wellbore hydrodynamics on the refrac treatment distribution is very important. Wellbore friction is believed to be a minor reason for the heel-biased treatment distribution compared to proppant inertia, which could lead to the pre-mature screen out of the toe-side clusters.
Simulation results show that using small refrac stages with more frequent diverting agent application can help avoid over-stimulating the dominant fractures and promote more uniform fracture propagation. Strategies that moderate the proppant inertia could also help mitigate the heel-biased trend of refrac treatment distribution.
Improving oil recovery from unconventional liquid reservoirs (ULRs) is a major challenge. We have demonstrated in previous laboratory studies the effect of surfactants on spontaneous imbibition and oil recovery by means of wettability alteration and interfacial-tension (IFT) reduction. Thereby, fracture-treatment performance and consequently oil recovery could be improved by adding surfactants to stimulation fluids when a soaking/flowback production schedule is applied. This study evaluates the ability of different groups of surfactants to improve oil recovery in ULRs by experimentally simulating the fracture treatment to represent surfactant imbibition in a ULR core fracture during soaking and flowback. In addition, we analyze the effects of wettability and IFT alteration as well as surfactant adsorption on the process. A coreflooding system was combined with the computed-tomography (CT) scanner to dynamically visualize the fluid movement as it penetrates the ULR sample in real time as well as compare oil recovery between surfactants and water without additive. Wolfcamp sidewall cores were longitudinally fractured and loaded into an aluminum/carbon-composite core holder. Two different types of surfactants—anionic and nonionic/cationic—as well as water without surfactants were injected through the fractures at reservoir conditions to evaluate their effectiveness in penetrating into the fractures and recovering oil from a ULR core. Then, a soaking/flowback production scheme was used to simulate fracture treatment and flowback. Changes in core wettability and IFT were determined by contact-angle (CA) and pendant-drop methods. Coreflooding results showed that surfactant solutions had higher imbibition and recovered more oil from liquid-rich core compared with water alone. The soaking/flowback production schedule aided by surfactants was able to recover up to 14% of the original oil in place (OOIP), whereas water alone recovered up to 2% of the OOIP. These observations qualitatively agree with wettability- and IFT-alteration measurements. Core wettability shifted from an original oil-wet to a final water-wet state, and surfactants reduced IFT to moderately low values. In addition, surfactants showed adsorption capacity following a Langmuir-type adsorption profile. The results showed that the addition of surfactants to completion fluids and the use of a soaking/flowback production scheme could improve oil recovery by wettability alteration and IFT reduction, maximizing well performance after stimulation. These findings provide an important understanding for designing completion-fluid treatments and flowback schedules for ULRs.
Ishank Gupta, Chandra Rai, Carl Sondergeld, and Deepak Devegowda, University of Oklahoma Summary Different decline-curve-analysis (DCA) methods have been proposed to predict the production performance of both conventional and unconventional-shale reservoirs. These methods range from empirical to semiempirical and theoretical. The different methods were developed using specific data sets and have their own assumptions and limitations, and thus are not universally applicable. This study shows that a DCA method should be capable of simultaneously modeling the flow regime prevalent around the well and the changes in reservoir properties with time, to be able to successfully represent the production performance of the well and predict future performance. In shales, flow regimes can be linear, bilinear, multifracture linear, post-linear, stimulated-reservoir-volume (SRV) -dominated boundary flow, or compound linear. The change in fracture conductivity caused by fines migration, embedment, crushing, diagenesis, and change in stresses because of production is another important phenomenon for which a DCA method must account. This study critically analyzes various proposed historical DCA methods with respect to their capability to model fracture-flow regimes and changes in fracture conductivity with time. Upon close examination, it was found that both the linear-flow regimes and changes in fracture conductivity with time follow a power-law function. Thus, the reason for the successful application of the Arps (1944) hyperbolic, power-law-exponential (PLE), stretched-exponential-decline (SEPD), and Duong (2010) methods is that decline rates in these methods are a power-law function or can be closely approximated by a power-law function.
Fracture stimulation of horizontal wells in unconventional gas-or oil-producing reservoirs by placing a large number of transverse or pseudo transverse fractures in reference to the wellbore orientation is usually necessary to help maximize hydrocarbon recovery in complex environments. Although economic completion and multistage fracture stimulation of unconventional reservoir using horizontal wells dates back to mid-2002, particularly in North America, it has been gradually modified and improved through extensive trial and error processes to improve the stimulation effectiveness in unconventional reservoir productivity. However, the trial and error process is not often effective nor a recommended practice in the refracturing processes where differential areal depletion is present. This paper demonstrates the effect of differential depletion normally present in existing unconventional producing reservoirs and how to optimize additional fracture(s) placement during refracturing processes or infill well placement to help maximize hydrocarbon recovery. In line with the economic considerations and the massive implementation of completion activities, the industry has often applied the trial and error process in the unconventional reservoir. Initial completions involve variations of (but not limited to): pumping rate, total lateral length, spacing and number of perforation clusters, perforations per cluster, lateral length of treated stages, length of fractures generated, proppant and stimulation fluid volumes per stage, and lateral well spacing. The initial completion strategy was often intended to prevent or minimize the negative effect of interferences or non-effective completion techniques which could result in the use of longer perforation clusters, longer fracture stage spacing, or conservative completions. Additionally, if the completion design is not effective in maximizing the fracture initiation points per stimulation stage, a significant bypass of hydrocarbon reserves between the fractures or well laterals can happen. To produce the additional bypassed hydrocarbon reserves, an engineered process to refracture existing wells should be implemented if they are economically justified.
Wüst, Raphael A. J. (AGAT Laboratories, Calgary) | Mattucci, Mike (ChemTerra Innovation, Calgary) | Hawkes, Robert (Trican Well Service LTD., Calgary) | Quintero, Harvey (ChemTerra Innovation, Calgary) | Sessarego, Sebastian (ChemTerra Innovation, Calgary)
The Devonian Duvernay Formation in Alberta, characterized as a carbonate-siliceous source rock, is ramping up to be one of the largest and most prolific shale oil plays in Canada. In the southern part of the Duvernay Shale Basin (i.e. East Shale Basin), tight limestone beds are interbedded with laminated organic-rich calcareous shales, which show an organic maturity ranging mostly from early oil- to condensate-window. This new light oil shale play is still in the initial stages of development and the nature of these deposits requires hydraulic fracturing to increase stimulated rock volume. General completion programs involve ≥50 clustered plug ‘n’ perf stages with slickwater treatments in excess of 40,000 m3 with ~4000 tonnes of proppant per well. The large water volume treatments will inevitably interact directly with the rock surface in the stimulated area and cause both oil-water and rock-water interactions. Post-hydraulic fracturing water retention is especially pronounced in light oil shale plays. The oil-wet nature of the Duvernay, along with calcareous and siliceous shale lithologies, adds to the complexity of water retention and perceived water-blockage. In addition, because of operational delays such as road bans and pipeline constraints, some wells may be shut-in after the fracturing treatment for weeks and even months, which will affect rock-oil-water behavior (i.e. production). The extent of water displacing into the matrix of the rocks of the Duvernay Formation in the East Shale Basin, as measured by load fluid recovery, varies significantly and appears to heavily rely on the choice of surfactant. Although the use of surfactants is generally accepted for this play, detailed understanding of the rock-fluid interaction mechanisms is still incomplete.
This paper investigated the response of Duvernay Shale rocks from the East Shale Basin to various types of surfactants and analyzed production and fluid flowback data. Amott Cell analyses, which test for spontaneous oil displacement using various stimulation fluid types, demonstrated that in the East Shale Basin, nano-sized surfactants including multi-functional surfactants (MFS) and microemulsions significantly outperformed common surfactant chemistry when tested with mixed wettability shale core samples. The results provide an estimate as to extent of water migration into the matrix of the Duvernay as a result of the choice of surfactant. Our analysis is made possible from publicly available cores, laboratory analysis and high quality well production data from the Alberta Energy Regulator.
The present study used the workflow presented in
The workflow incorporates conducting three systematic imbibition experiments for a same shale core sample using brine, slickwater, and brine again. The sample brine permeability was measured before and after the imbibition experiments using a constant rate steady-state permeability setup.
The results showed that the polymer adsorption reduces the brine spontaneous imbibition volumes. Moreover, the shale petrophysical properties could dominate the polymer adsorption more than the mineralogical composition.
Adding a non-ionic surfactant to the slickwater enhanced the imbibition rate considerably into both of the Barnett and Marcellus shale samples, and that improves the fluid flowback in these shales.
The bedding planes and their orientation are among the factors that control the effect of the polymer adsorption on the fluid imbibition rate. The more obvious are the bedding planes, the higher impact of the polymer adsorption on the fluid imbibition rate. However, the petrophysical properties have more effect on the shale prone to adsorb the polymer than the bedding plane orientation.
The effect of the polymer adsorption slightly increased the capillary pressure curve. However, as the porosity and permeability increase, the effect of the polymer adsorption on the capillary pressure increases. In comparison to the Eagle Ford shale, the Barnett and Marcellus shales had lower capillary pressure, and that could be one of the reasons of their higher fluid flowback. The impact of the polymer adsorption on the water relative permeability was less for the Barnett sample in comparison to the Marcellus sample because of its lower porosity and permeability.
Four intact one-inch diameter cores from different shale plays (Barnett, Haynesville, Eagle Ford, and Permian Basin) were analyzed for their gas storage capacity using a novel multiscale imaging methodology spanning from cm- to nm-scale. Gas storage capacity was investigated at the core-scale with carbon dioxide (CO2) and krypton (Kr) using X-ray computed tomography (CT) with voxel dimensions of 190×190×1000 μm. Also, 2D tiled images were acquired using a scanning electron microscope (SEM) and stitched together to form one-inch diameter mosaics with a pixel resolution of 1.5 μm. Multiscale image registration was then carried out to align the CT data with the SEM mosaics. Energy dispersive spectroscopy (EDS) generated elemental spectra maps and subsequent component maps for regions with either substantial or minimal gas storage to assess the interplay of structural features (e.g., fractures) and matrix composition with respect to gas accessibility and adsorption.
Registration of CT scans (vacuumed and gas-filled) as well as 190 µm-resolution CT-derived gas storage maps with 1.5 µm-resolution SEM mosaics is straight forward for samples with dense features (such as calcite-filled fractures) that are resolvable by CT imaging. Alignment methods were developed for samples lacking these features including registration marks using silver paint and intermediate resolution microCT scans with cubic voxel dimensions of 27 μm. Once aligned, the relationship of enhanced adsorption zones with open fractures and reduced adsorption regions with secondary mineralization (such as nodules) is apparent for the carbonaceous samples. For the clay-rich Barnett sample, fracture-filling calcite is associated with reduced adsorption similar to the other samples; however, secondary carbonate cementation within the clay matrix aligns with regions with substantial Kr and CO2 gas storage. In contrast, clay-rich matrix regions lacking secondary carbonate cementation exhibit minimal gas storage potential. Causes for this unexpected result include reduced gas accessibility and, possibly, low organic matter content in the clay-rich matrix compared to secondary cemented matrix.
These gas adsorption experiments prove the feasibility of dynamic core- to nm-scale CT/SEM/EDS image registration to improve sample characterization. To our knowledge, this is the first investigation of core-scale CO2 gas adsorption employing multiscale imaging. CT and SEM image registration reveal spatial details regarding gas accessibility and storativity at the core-scale. This work also supports the potential of carbon storage in shale formations as well as guides engineers toward optimal CO2 injection zones for enhanced gas recovery.