Cronkwright, David (University of Calgary) | Ghanizadeh, Amin (University of Calgary) | DeBuhr, Chris (University of Calgary) | Song, Chengyao (University of Calgary) | Deglint, Hanford (University of Calgary) | Clarkson, Chris (University of Calgary) | Ardakani, Omid (Geological Survey of Canada)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 22-24 July 2019. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Fluid distribution and fluid-rock interactions within the nano-/macro-porous pore network of tight oil reservoirs will affect both primary and enhanced oil recovery (EOR) processes. Focusing on selected samples obtained from the liquids-rich reservoirs within the Montney Formation (Canada), the primary objective of this work is to evaluate the impact of mineralogical composition on micro-scale fluid distribution at different saturation states: 1) "partially-preserved" and 2) after a series of core-flooding experiments using reservoir fluids (oil, brine) under "in-situ" stress conditions. Small rock chips (cm-sized), sub-sampled from "partially-preserved" (using dry ice) core plugs, were cryogenically frozen and analyzed using an environmental field emission scanning electron microscope (E-FESEM) equipped with X-ray mapping capability (EDS).
Manchanda, Ripudaman (The University of Texas at Austin) | Zheng, Shuang (The University of Texas at Austin) | Gala, Deepen (ExxonMobil Upstream Research Company) | Sharma, Mukul (The University of Texas at Austin)
Horizontal well fracturing is an established practice to improve the recovery of hydrocarbons from oil and gas reservoirs. To simulate fracture propagation, fracture closure during production and fracture reopening during fluid re-injection, it is essential to combine three important aspects of the problem: multiphase flow, geomechanics and fracture propagation. Current simulation software utilize separate models for these processes. Our objective in this paper is to present a streamlined workflow that we have developed to integrate these highly coupled processes into a single computationally efficient simulation model.
A fully coupled 3-D geomechanical reservoir simulator has been developed to perform multi-cluster hydraulic fracturing and reservoir simulations. The model (Multi-Frac-Res) uses coupled fluid and proppant transport in the fracture with multi-phase reservoir flow and reservoir stresses, in one system of equations. It also accurately models fluid and proppant distribution between multiple perforation clusters in the wellbore. Fracture closure during shut-in or production requires the use of implicit contact models and these models account for the impact of proppant embedment on fracture conductivity. The coupled system allows for seamless transition between fracture propagation, fracture closure, reservoir production and re-injection. This is done in one streamlined workflow without the need for inefficient transfer of information between different simulation software.
An effective hydraulic fracturing treatment aims at maximizing the EUR while maintaining high hydrocarbon production rates. The integrated model allows us to directly evaluate the impact of cluster spacing, frac fluid injection rate, proppant volume, and drawdown on the effectiveness of a hydraulic fracturing treatment. Simulation results are presented that show the relative importance of all the above parameters during the lifecycle of a typical horizontal well. We show how smaller cluster spacing can cause more interference between fractures and hamper the EUR. Larger proppant volume is shown to improve the conductivity of the created fractures and improve the productivity. Faster drawdown is shown to cause faster depletion and faster closure of the fracture but also helps in producing more fluid. Changes in the stress field around the fracture are presented and are shown to impact the growth of fractures in in-fill wells as well as the performance of refracturing treatments. These poroelastic effects are also shown to play a very important role in the growth and reorientation of fractures in injection wells during waterflooding.
Current simulation software utilize separate models for these processes leading to inefficient data transfer between several models that can cause loss of data. This study showcases an integrated model that can simulate the lifecycle of hydraulically fractured wells all the way from creation of the hydraulic fractures to production and reinjection and allows for a holistic comparison between scenarios by comparing productivity numbers and EUR estimates.
Malpani, Raj (Schlumberger) | Alimahomed, Farhan (Schlumberger) | Defeu, Cyrille (Schlumberger) | Green, Larrez (MDC Texas Energy) | Alimahomed, Adnan (MDC Texas Energy) | Valle, Laine (MDC Texas Energy) | Entzminger, David (MDC Texas Energy) | Tovar, David (Schlumberger)
As well density in a section increases, drilling and completions decisions regarding the stimulation of infill wells are increasingly informed by changes in the in-situ stress, mechanical properties, and material balance that result from depletion around parent wells. This is a multifaceted reservoir-dependent four-dimensional problem with many different dependencies. Accordingly, projects involving parent-child interactions during the completion phase are carefully planned using sound engineering principles to avoid negative effects of depletion and fracture hits. We present a case study from a section development in the Wolfcamp formation. Multiple wells drilled at various times are chronologically described below:
1) Parent well in the middle of the section – generation I
2) Child well 1 to the western edge of the section (2 months after parent well) – generation II
3) Child well 2 to the eastern edge of the section (2 months after child well 1) – generation II
4) Child well 3A between parent well and child well 1 (6 months after child well 2) – generation III
5) Child wells 3B, 3C, and 3D (drilled from the same pad) between parent well and child 2 (6 months after child well 2) – generation III
All wells but child 3D are in the same horizon. Downhole and surface gauges were installed on all observation wells during the completion infill wells (child 3A, 3B, 3C, and 3D). Water injection treatment was performed on the existing wells (parent, child 1, and child 2) wells prior to completing generation III infill wells. Child well 3A was completed first to build up pressure on the west side of the section. Child wells 3B, 3C, and 3D were from same pad on the surface and were zipper fractured. Design changes were made to the completion program with contingencies built-in to make additional changes on the fly to incorporate field geometry control aids and reduction to injection rate and fluid volume.
The parent well experienced fracture hits during completion of child 1 and child 2, spaced at ~2,500 ft. Chemical tracers and production behavior suggested that even a few months of production led to pressure reduction in the section. During completion of child wells 3A, 3B, 3C, and 3D, multiple pressure increases were observed on the parent and child 2 wells with varying degree of severity, but no fracture hit. The stress buffer (shadow) created by carefully sequencing the stimulation program aided in reducing the fracture communication. The fluid injection strategy was effective in reducing the magnitude of pressure communication. Additionally, an active pressure-monitoring program and real-time design changes were able to prevent fracture hits.
The tracer data and productivity index (PI) profile suggest that during stimulation, wells have been hydraulically connected; even though the connections fade over time, results in overall of lowering of reservoir pressure. Some sections do show abnormal behavior likely due to localize geological features. The initial PI for the child 3A, child 3B, and child 3C is smaller than that of the parent well, like child 1 and child 2 wells. All wells in Wolfcamp A shows similar PI profile after all the wells were put back on production, except for child 3A. Child 3D well (Wolfcamp B) has higher PI than other generation III wells pointing to no or minimal communication between the two formations. The infill wells (generation III) have increased water cut than the existing wells (generations I and II). Child 3D well is in Wolfcamp B, which has higher water saturation as compared to Wolfcamp A in the area.
Wells with spacing above 1,000 ft show equivalent productivity, but wells less than 500 ft apart show inferior productivity. The optimum well spacing with the general completion and stimulation design in the area seems to be within 500 ft to 1,000 ft (5 to 10 wells in a section) in this area in Wolfcamp A. The results also suggest that hydraulic connectivity from Wolfcamp B to Wolfcamp A but the production seems to be isolated from Wolfcamp A. Developing a section with depletion effects occurring at various distances and durations is challenging. Our proactive approach of designing, monitoring, and responding provides insights into the development of multigeneration wells in the Wolfcamp formation and in similar settings around the world.
We analyzed flowback (FB) and post-flowback (PFB) production data from six multi-fractured horizontal wells completed in Eagle Ford Formation. The wells are supercharged at the beginning of the flowback process and the reservoir pressure remains above bubble point during the post-flowback period. Interestingly, we observe a pronounced unit slope (pseudo-steady state) in the rate-normalized pressure (RNP) plots of water for post-flowback period, while such unit slope is not observed for the flowback period. We developed a conceptual and mathematical model to describe these observations and to estimate the average fracture pore volume (Vf) during the post-flowback process. This model assumes no water influx from matrix into the fracture system, which is consistent with the lack of mobile water in the target reservoir. It also assumes stable influx of oil from matrix into the fracture system with insignificant mass accumulation of oil in the fracture system. Therefore, water production at pseudo-steady state conditions occurs under the driving forces of water expansion, oil expansion, and fracture closure. We also performed decline curve analysis on water production data to estimate initial Vf, as the fractures tend to be fully saturated with water at the beginning of the flowback process. The difference between ultimate water recovery and average Vf from the PFB model represents the loss in fracture volume due to fracture closure. The results show that about 65% of fracture closure occurs after 7 months of PFB production. Fracture closure is the dominant drive mechanism during FB and early PFB periods when reservoir pressure drops rapidly.
Analysis of flowback is becoming a common practice for early characterization of fractured horizontal wells completed in unconventional reservoirs. Several authors have developed different models for analyzing early flowback data to characterize complex fracture networks created by multi-fractured horizontal wells. Examples of recent studies include Abbasi et al. (2012, 2014), Ezulike et al. (2013), Clarkson and Williams-Kovacs (2013), Ezulike and Dehghanpour (2014a, b), Jia et al. (2015), Xu et al. (2016), Ezulike et al. (2016), Yang et al. (2016), Williams-Kovacs (2017) and Chen et al. (2017).
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:
In the Dunvegan Kaybob South Pool, recent multistage fracked horizontal wells have revealed the presence of a light oil play enveloping a large legacy gas field, developed with vertical wells. The boundary between the oil and gas producing areas intersect structural contours a high angle within deltaic sandstones of the Cretaceous Dunvegan Formation. To address controls on this boundary, a multidisciplinary study of cores, core analysis data, well logs was completed and integrated with test and production data to identify controls on fluid production.
Legacy gas production is from relatively high permeability delta front sandstones, while oil dominated production occurs from lower permeability, fine grained pro-delta deposits. While wells within the legacy gas field produce very low volumes of oil, core fluid extractions reveal significant oil is also present within this portion of the reservoir, but is not mobile. The Dunvegan clearly demonstrates permeability as the main control on the anomalous fluid distributions, with several other tight sandstone plays showing similar relationships, although often more subtle, such as observed in the Cardium, Montney, etc.
The anomalous fluid distributions with higher gas saturations in higher permeability beds and higher oil saturation in lower reservoir quality beds contradict conventional capillary reservoir charge models. Thus, we propose late stage migration of predominantly gas related to the increase in gas generation post peak oil window due to increasing maturity of the kerogen during burial. These late generated gas fluids migrated from the deeper part of the basin preferentially within higher permeability strata and fractures, and displace the earlier emplaced oil resulting in reservoirs with high GOR. These counterintuitive observations with higher liquids production from lower reservoir quality, can significantly improve the play economics and allow better prediction of fluid distribution in many plays.
Although unconventional low permeability reservoirs form laterally continuous thick hydrocarbon accumulations, they often have variable liquid saturations vertically and laterally. While varying kerogen type and maturity are important controls. In several plays, fluid distribution shows a strong correlation with permeability, with higher gas saturations occurring in more permeable beds. The control of permeability on anomalous fluid distribution has been discussed for several clastic, low permeability unconventional light oil and liquid rich gas plays in the Western Canada Sedimentary Basin (e.g. Wood and Sanei 2016, Venieri and Pedersen 2017). In this study we present a study of a legacy gas pool producing from deltaic sandstone reservoirs of the late Cretaceous Dunvegan Formation (Figure 1). The pool is located within the deep basin of western Alberta, an area of pervasive hydrocarbon saturation charged by enveloping thermal mature organic rich mudstones and coals (Masters 1984). The Dunvegan Kaybob South Pool is comprised of a lowstand delta lobe of the southward prograding Dunvegan Delta (Bhattacharya 1993).
Clarkson, Christopher R. (University of Calgary) | Yuan, Bin (University of Calgary) | Zhang, Zhenzihao (University of Calgary) | Tabasinejad, Farshad (University of Calgary) | Behmanesh, Hamid (NCS Multistage) | Hamdi, Hamidreza (University of Calgary) | Anderson, Dave (NCS Multistage) | Thompson, John (NCS Multistage) | Lougheed, Dylan (NCS Multistage)
The dominant transient flow regime for multi-fractured horizontal wells producing from low-permeability and shale (unconventional) reservoirs has historically been interpreted to be transient linear flow (TLF) in the framework of classical diffusion (CD). Recently, observed deviations away from this classical behavior for Permian Basin Wolfcamp shale (oil) wells have been attributed to anomalous diffusion (AD). The objective of the current study is to systematically investigate other potential causes of deviations from TLF.
The conventional log-log diagnostics used to identify flow regimes do not account for reservoir complexities such as multi-phase flow and reservoir heterogeneity. Failure to correct for these effects when they are occurring may result in misdiagnosis of flow regimes. A new workflow is therefore introduced herein to improve flow regime identification when reservoir complexities are exhibited, and to provide a more confident diagnosis of AD behavior. The workflow involves the correction of log-log diagnostics for complex reservoir behavior through the use of modified pseudo-variables (pseudo-pressure and pseudo-time) after the complex reservoir behavior is identified. Although reservoir heterogeneity is an accepted cause of deviations from TLF, the impact of multi-phase flow has not been investigated in detail. Therefore, in this study, corrections to pseudo-variables for multi-phase flow, a known reservoir complexity exhibited by Wolfcamp shale wells, are presented. Pressure-dependent permeability is also accounted for in the pseudo-variable calculations, although its impact is demonstrated to be relatively minor in this study.
Application of the new workflow to a simulated case and a Wolfcamp shale field case demonstrates the following: 1) multi-phase flow, and in particular the appearance of a mobile gas phase after two-phase oil and water production, results in deviations from classical TLF behavior when data is analyzed using conventional (uncorrected) diagnostics; 2) this deviation has characteristics similar to that expected for sub-diffusion; 3) application of the modified diagnostics to a simulated case that includes multi-phase flow results in the “true” flow regime signature of TLF being observed; 4) application of the modified diagnostics to a field case exhibiting evidence of multi-phase flow reduces the deviation from TLF.
Applications, Significance, and Novelty: The proposed methodology may be widely applied, since it relies on available standard well and completion data. This method can be used on (i) legacy projects where offset pressure data was recorded; (ii) post job analysis of recent completions, and (iii) near real-time analysis of current completions.
Zhang, Zhenzihao (University of Calgary) | Clarkson, Christopher (University of Calgary) | Williams-Kovacs, Jesse (University of Calgary) | Yuan, Bin (University of Calgary) | Ghanizadeh, Amin (University of Calgary)
Quantitative flowback analysis can be used to obtain early hydraulic fracture property estimates which, in turn, can be used to guide stimulation and well operations decisions on future wells/pads. Most quantitative studies of flowback data have primarily utilized rate and pressure data to derive fracture/reservoir properties. However, salinity data contains important additional information that can be used to constrain flowback modeling. In this work, salt transport modeling is combined with a previously-developed frac-through-flowback model based on the dynamic drainage area (DDA) concept in order to constrain the reservoir matrix and hydraulic fracture property estimates. The mechanisms of salt mixing, dispersion/diffusion and advection are captured in the salt-transport model.
In previous work, an integrated model comprised of the following components was developed: 1) hydraulic fracture propagation and proppant transport model; 2) leakoff model; and 3) flowback model. The integration of these components has proven useful for a) constraining hydraulic fracture property estimates (e.g. fracture half-length) and b) modeling the initial pressure and saturation conditions in the fractures and reservoir at the start of flowback. The inclusion of salt transport modeling during flowback to match salinity profiles also helps to constrain matrix and fracture property estimates. For this purpose, salt mixing, dispersion/diffusion, and advection during hydraulic fracturing treatment, subsequent shut-in, and flowback are modeled using a finite-difference-based salt-transport model coupled with a black-oil simulator. The salt transport model was validated against the analytical solution for a diffusion-advection problem, while the black-oil simulator was verified with CMG®-IMEXTM. The coupled salt-transport/black-oil simulator was then tested against a field case to demonstrate its practical applicability.
Water salinity during flowback was precisely matched using the coupled salt-transport/black-oil simulator for the field case. The matrix permeability evaluated using the frac-through-flowback model was constrained by history matching the flowback salinity data using the developed simulator. Laboratory-derived stress-dependent properties served to reduce the number of simulation runs performed during history-matching. The distribution of chemical species in the reservoir was tracked using the new model. Advection and advection-related dispersion were found to be the dominant mechanisms affecting flowback salinity, contrary to the findings of some previous studies.
Rivero, Jose A. (Schlumberger Canada) | Faskhoodi, Majid (Schlumberger Canada) | Ferrer, Giselle Garcia (Schlumberger Canada) | Mukisa, Herman (Schlumberger Canada) | Zhmodik, Alexey (Schlumberger Canada)
In unconventional reservoirs that rely on hydraulic fractures for production, displacement Enhanced Oil Recovery (EOR) methods are difficult to apply due to the low matrix permeabilities that impede the flow of the injected agents through the formation. This leaves cyclic methods, also known as huff-and-puff as one of the possible alternatives for improving recovery in these types of reservoirs.
Since 2014, a considerable amount of literature and research has been devoted to the feasibility, implementation and optimization of gas Huff-and-Puff in fractured unconventionals. Most of these studies have been devoted to oil reservoirs and few publications have addresses gas condensates.
In this study, we investigate the feasibility of using lean hydrocarbon gas mixtures to increase recovery in a typical gas condensate reservoir in the Montney formation. To perform this study, we used publicly available data to build a representative Montney gas condensate reservoir. A finite-element hydraulic fracture simulator was employed to create a series of hydraulic fracture geometries that were later modeled with a compositional reservoir simulator to forecast primary production and liquid recovery under different Huff-and-Puff scenarios. We conducted sensitivity studies to test the effect of the injected gas composition and soaking time. Additionally, the impact of fracture geometries (complex vs. planar) was also investigated.
We found that soaking time had a measurable effect on liquid recovery as it allows the pressures between the fractures and matrix to equilibrate, thereby affecting the volume of condensate that can revaporize. The choice of solvent has a strong effect on the amount of condensate uplift, with leaner gasses recovering less. Finally, higher incremental liquids production with Huff-and-Puff was strongly correlated with higher pressures since they allowed for more re-vaporization. Fracture geometries were found to have considerable influence on the pressure profiles during the production and injection periods; therefore, the degree of complexity of the fracture played a role in the performance of the EOR process.