A hybrid-hydraulic-fracture (HHF) model composed of (1) complex discrete fracture networks (DFNs) and (2) planar fractures is proposed for modeling the stimulated reservoir volume (SRV). Modeling the SRV is complex and requires a synergetic approach between geophysics, petrophysics, and reservoir engineering. The objective of this paper is to characterize and evaluate the SRV in nine horizontal multilaterals covering the Muskwa, Otter Park, and Evie Formations in the Horn River Shale in Canada, with a view to match their production histories and to evaluate the effectiveness and potential problems of the multistage hydraulic-fracturing jobs performed in the nine laterals.
To accomplish this goal, the HHF model is run in a numerical-simulation model to evaluate the SRV performance in planar and complex fracture networks using good-quality microseismicity data collected during 75 stages of hydraulic fracturing (out of 145 stages performed in nine laterals). The fracture-network geometry for each hydraulic-fracture (HF) stage is developed on the basis of microseismicity observations and the limits obtained in the fracture-propagation modeling. Post-fracturing production is appraised with rate-transient analysis (RTA) for determining effective permeability under flowing conditions. Results are compared with the HHF simulation and the hydraulic-fracturing design.
The HHF modeling of the SRV leads to a good match of the post-fracturing production history. The HHF simulation indicates interference between stages. The vertical connectivity in the reservoir is larger than the horizontal connectivity. This is interpreted to be the result of the large height achieved by HFs, and the absence of barriers between the formations.
It is concluded that the HHF model is a valuable tool for evaluating hydraulic-fracturing jobs and the SRV in shales of the Horn River Basin in Canada. Because of the generality of the Horn River application, the same approach might have application in other shale gas reservoirs around the world.
Dumas, Guilherme E. S. (Petrobras E&P) | Freire, Ednilson B. (Petrobras E&P) | Johann, Paulo R. S. (Petrobras E&P) | Silva, Luciana S. (Petrobras E&P) | Vieira, Roberto A. B. (Petrobras E&P) | Bruhn, Carlos H. L. (Petrobras E&P) | Pinto, Antonio C. C. (Petrobras E&P)
Over the last 40 years Petrobras has developed several oilfields in the prolific Campos Basin, including giant fields such as Marlim, Roncador and Jubarte, among others. All of these giant fields produce mostly from siliciclastic turbidite reservoirs, ranging in age from Albian to Miocene, which contain medium API gravity oil (mostly 18 – 24°API). Sea water injection is the main method for improving oil recovery. Reservoir management is particularly complex because of the deep to ultra-deep water depth and the use of subsea well completion. Therefore, several methodologies, tools and technologies are required to help reservoir management, such as: (1) data acquisition for reducing reservoir uncertainties, including extended well tests in the development plan design phase; (2) continuous improvement in the reservoir characterization and modeling incorporating dynamic data; (3) 4D seismic for monitoring oil and gas production, allowing the identification of areas with bypassed oil and secondary gas caps; (4) single well and inter-well tracers and production logs, also to help tracking the remaining oil; (5) infill drilling, to replace high water cut wells by wells located in areas with low water saturation; (6) produced water reinjection; (7) remote well treatment to restore water injectivity, as well as to inhibit or remove inorganic scaling in production wells; and (8) active reservoir management aiming the optimization of well production and injection rates, based on the flow simulator and field responses. The results have been so far very good, with the reduction of production losses and the gradual increasing in the ultimate recovery factor. A good example is provided by the Marlim Field, that already reached an oil recovery of 40%, and the actions planned for the field revitalization indicate an ultimate recovery factor of over 50%.
A hybrid hydraulic fracture (HHF) model composed of (1) complex discrete fracture networks (DFN) and (2) planar fractures is proposed for modeling the stimulated reservoir volume (SRV). Modeling the SRV is complex and requires a synergetic approach between geophysics, petrophysics, and reservoir engineering. The objective of this paper is to characterize and evaluate the SRV considering the initial hydraulic fracturing efficiency, fracture network complexity, mechanics, and microseismicity distribution along 145 stimulated stages in a multilateral horizontal well on the Muskwa, Otter Park and Evie Formations in the Horn River Shale in Canada.
Hydraulic fracturing jobs in shale reservoirs are designed with a view to achieve economic production by exploiting fracture network complexity. The task involves significant challenges in modeling and forecasting, which complicates the examination of operations to enhance their performance, including refracturing or infill drilling.
In this study, an HHF is run in a numerical simulation model to evaluate the SRV performance in planar and complex fracture networks using microseismicity data collected during 75 stages of hydraulic fracturing in the Horn River shale. Post-fracturing production is appraised with Rate Transient Analysis (RTA) for determining effective permeability under flowing conditions, compare to the numerical simulation and the hydraulic fracturing design.
Fracturing stages with larger fracture patch sizes, associated with the microseismic events in a fixed stress drop, correspond to higher stimulated areas, fracture conductivity, and gas production. Several microseismic events are observed in the heel of the laterals that are aligned to the far field NE stresses, indicated a loss of efficiency along the wellbore lateral during hydraulic fracturing. The hydraulic propagation modeling revealed increment of the leak-off coefficient, related to the natural fractures and communication with other stages. The production performance is evaluated in the numerical model, to measure interference between stages.
The SRV, modeled with HHF networks, is able to match the post-fracturing production history. Fracture mechanics is important in order to understand the flowing performance of the reservoir.
The inclusion of propagating models and RTA allowed to characterize possible fracture geometries in the reservoir and to observe limitations inherent to large dispersion and uncertainty of the microseismicity cloud. Also, to observe areas where the stimulation may have propped natural fractures totally or partially, which will benefit the production of gas.
This study presents a better understanding and characterization of the SRV in shale gas reservoirs, especially in those cases where microseismicity dispersion is problematic and where the SRV is not easily delimited.
Perz, Michael (TGS) | Chopra, Satinder (TGS) | Sharma, Ritesh (TGS) | Cary, Peter (TGS) | Li, Xinxiang (Arcis Seismic Solutions) | Ohlhauser, Wendy (Arcis Seismic Solutions) | Pike, Kimberly (PennWest) | Creaser, Brian (Enerplus) | Nemati, M. Hossein (Arcis)
A high-effort, multicomponent 3C3D seismic data set was acquired over a mature oil field in central Alberta in order to better understand the characteristics of a waterflood operation. True-amplitude processing of the data was undertaken, and joint PP-PS prestack impedance inversion reveals a pronounced set of anomalous low-impedance lineaments at the target level which exhibit a very strong spatial correlation with known water injector locations. Rock physics modeling demonstrates that fluid pressure effects are heavily influencing the seismic response in the vicinity of the injectors, and are accounting for the observed low-impedance anomalies. Analysis of injection and production data suggests that the seismic data can play a vital role in identifying zones of unswept pay in this area.
Presentation Date: Monday, October 17, 2016
Start Time: 1:00:00 PM
Presentation Type: ORAL
Madsen, M. (Whiting Petroleum Corporation) | Carlson, J. E. (Whiting Petroleum Corporation) | Rondon, J. R. (Schlumberger) | Valenca, A. (Schlumberger) | Do, T. (Schlumberger) | Stewart, M. (Schlumberger) | Borchardt, E. (Schlumberger) | Dupuis, B. (Schlumberger)
A well which was drilled in the Pronghorn formation of the Williston Basin had significant trouble during the cementing process. While the lateral length was 11,103 feet, only the 9,296 feet of the lateral closest to the toe had adequate cement to provide the isolation needed for hydraulic fracture stimulation. An integrated solution with evaluation of well integrity and novel diversion material used over the remaining 1,807 feet of the lateral to generate multiple hydraulic fractures was proposed and results were confirmed with production log evaluation.
After using an ultrasonic imaging logging tool conveyed via tractor to determine the point at which the cement isolation became unreliable, the appropriate completion was designed. The first 33 stages of the stimulation were done using a standard plug and perf technique. The last 1,807 feet of the lateral were completed in two intervals with only one additional bridge plug. The two intervals were each stimulated with seven hydraulic fracturing stages and six diversion pills consisting of a proprietary blend of degradable materials. While more stages were pumped in the heel section, the same amount of proppant per foot of lateral was used as in the larger conventionally completed toe section.
The 14 stages pumped in the heel portion of the lateral showed that in both intervals, the instantaneous shut-in pressures at the end of each one of them increased by 2,300 psi and 340 psi respectively. This increase is consistent with fractures initiating at lower pressure intervals, and then being diverted to higher pressure, unstimulated areas. Well production was evaluated with a production log capable of identifying multiphase holdup along the lateral. This evaluation showed that 42% of the total oil production was coming from the 18% of the lateral which was stimulated using the degradable diversion material.
The application of this degradable diversion material in poorly cemented or un-cemented lateral sections in order to create a more uniform distribution of hydraulic fractures can significantly improve both completion efficiency and hydrocarbon production.
Hydraulic fracturing in shale gas reservoirs has often resulted in complex fracture network growth, as evidenced by microseismic monitoring. The nature and degree of fracture complexity must be clearly understood to optimize stimulation design and completion strategy. Unfortunately, the existing single planar fracture models used in the industry today are not able to simulate complex fracture networks.
A recently developed unconventional complex fracture propagation model is able to simulate complex fracture network propagation in a formation with pre-existing natural fractures. Multiple fracture branches can propagate simultaneously and intersect/cross each other. This paper presents an integrated operator, non-operator and service provider's approach to optimize future hydraulic fracture design by fully integrating all the data captured in the Canadian Horn River shale.
Based upon insight from the study, which was initiated by the non-operator, continued by the operator and supported by the service provider in two different countries, the operator and non-operator needed to make more informed design decisions and understand the interaction between the shale, the hydraulic and pre-existing natural fracture network and reduce costs.
Data were captured from reference vertical wells and a multi-well pad. The data incorporated into the study included geophysical, geological, petrophysical, geomechanical and engineering such as dfit (small volume of water pumped into target formation) derived fracture closure pressure, production and pressure data from the horizontal wells in the pad. A generation of 2D natural fracture network is also included in the paper by defining natural fracture parameters such as length, orientation, spacing, friction coefficient, cohesion, and toughness which are almost entirely validated using lab data and geomechanical interpretation.
The complex hydraulic fracture simulation results calibrated with microseismic and fracturing treatment data were incorporated into a shale gas, numerical simulator and further calibrated with current production history of the candidate multi-wells. The results of the hydraulic fracture, natural fracture and reservoir models were utilized to understand the fracture propagation mechanism in the Canadian Horn River shale gas formation.
As a result of the project, the team is now able to run different hydraulic fracture design scenarios and assess the impact that each key design parameter has over the candidate well's long term production using a numerical simulator with a unique gridding process. Based on these findings, the operator and non-operator now have an insightful tool that could be used as the building block for future optimization of the fracture design
Uncertainties in rock and soil engineering are connected with the cognitive boundaries and with the natural variability of the relevant variables. In particular, uncertainties are linked to geometrical and mechanical aspects and the model used for the problem schematization. While nothing can be done to remove the randomness of natural variables, except defining their variability boundaries with stochastic studies, the uncertainties due to the cognitive gaps could be filled by improving the quality of measuring instruments and numerical codes. The present paper considers uncertainties connected to the design of protection barriers against rockfall and contains a simple application of interval analysis to the problem, in order to quantify spacing influence on predicting rock block volume. A case study is also presented: block volume calculated from interval analysis is compared to results obtained from a non-contact survey and validated with in situ measurements. Also kinetic energy calculation is performed in order to show block volume influence on the design of a protection barrier.
The design of a geotechnical structure has inevitably to include the identification and the evaluation of a series of uncertainties due to the characteristics, the complexity and the non-homogeneous nature of the involved medium, either soil or rock. If the design concerns slope stability problems, the amount of uncertainties is further complicated. In fact, not only the time factor has to be considered as an additional variable, but also the spatial dimensions of the potentially involved areas. Therefore, for a better design in the rock engineering field, it is necessary to focus the attention on the involved uncertainties . The nature of the uncertainties in rock engineering is extensively discussed in literature. In , for example, sources of errors in sampling are classified as:
• Sampling error;
• Estimation (“statistical”) error;
• Measurement error.
The integration of an MPD system during a new drilling floater design phase is today a common practice. While working on a brand new project, different MPD technologies could be evaluated choosing the one that suit best next well campaign properties of each drilling contractor. At the design phase, technically speaking, almost everything can be arranged and integrated. Now, given the high appeal that MPD systems are reaching today within Oil Companies, and considering the best possible delivery time for a new floater, are we sure we will be granted all this time to wait? The idea of limiting MPD chances to new builds seems not to be wise, thus, the profitability of retrofitting this new philosophy on an existing drilling rig should be properly evaluated. Developing this assessment, it is easy to notice how the implementation of an MPD set up on a conventional drilling plant impose the designer a different approach. Limitations in space on decks, integration between new and existing equipment and need for crew training are just some of the criticalities the drilling contractor will face choosing the best solution for them within the increasing number of potential providers. Let's say "constrains" will drive the choice. The two major technologies available in the MPD market - and relevant set up - have been analysed on a "retrofitting point of view", highlighting benefits and deficiencies of each in a critical tradeoff between drilling development and operative constrains.
This paper aims at understanding the factors controlling the wettability of unconventional rocks. In the first part, we report the results of comparative imbibition experiments on several binary core plugs from the Montney tight gas formation, which is an enormous tight gas fairway in the Western Canadian Sedimentary Basin. Both contact angle and imbibition data indicate that the formation is strongly oil-wet. However, the ratio between oil and water imbibition rate of these samples is higher than what capillary-driven imbibition models predict. This discrepancy can be explained by the strong adsorption of oil on the surface of a well-connected organic pore network that is partly coated by pyrobitumen. We also define a wettability index by using the equilibrium imbibed volume of oil and water in binary plugs. Oil wettability index is in general positively correlated to the total organic carbon (TOC), measured by the Rock-Eval technique. In the second part, we report similar imbibition experiments on several binary core samples collected from the cores drilled in the shale members of the Horn River Basin. In contrast to the Montney (MT) samples, the Horn River (HR) samples imbibe significantly more water than oil. This observation contradicts the contact angle results which suggest that the HR samples are strongly oil-wet. Clay hydration, imbibition-induced microfractures, depositional lamination, and osmotic potential are collectively responsible for the excess water uptake. We also measure and compare spontaneous imbibition of oil and water into the crushed packs of the similar HR samples. Interestingly, in contrast to the intact samples, the crushed samples consistently imbibe more oil than water. The comparative study suggests that the connected pore network of the intact HR samples is water-wet while the majority of rock including poorly connected pores is oil-wet.Overall, the results suggest that the well-connected pore network of the MT samples is dominantly hydrophobic and is very likely to be coated by pyrobitumen. This is the main reason why these samples imbibe more oil than water. On the other hand, the well-connected pore network of the HR samples is strongly hydrophilic primarily due to the presence of clay minerals and precipitated salt crystals coating the rock grains.
Increasing the energy demand has shifted the industry focus towards unconventional resources worldwide. Recent advances in horizontal drilling and multi-lateral/multi-stage hydraulic fracturing has unlocked the challenging unconventional resources. However, successful and sustainable development of such reservoirs requires correct characterization of reservoir properties (Burke et al., 2011). In particular, knowing the reservoir rock properties such as permeability, porosity and wettability (wetting affinity) is critical for reserve estimation, production forecasting and designing optimum fracturing and treatment fluids.
The affinity of a reservoir rock on a particular fluid is defined as wettability, which depends on various factors such as rock mineralogy and the properties of the materials coating the rock surface (Anderson, 1986; Rao et al., 1994; Hamon, 2000; Mohammed B et al., 2010; Mohammadlou et al., 2012). Characterizing the wettability of reservoir rocks is important for 1) selecting fracturing and treatment fluids, 2) investigating residual phase saturation and its pore-scale topology, 3) investigating the occurrence water blockage at fracture face, and 4) selecting relevant capillary pressure and relative permeability models for reservoir engineering calculations.
A brief overview of different proppant types and amounts used in stimulation designs in the Bakken shale play since 2011 is presented in this paper. The primary goal of the paper is to determine the long-term production and economical effectiveness on hydraulically fractured wells using different proppant types, percentages of proppant types and overall amount of proppant in the well completions. The results are based on four case studies that focus on 72 wells in four different fields in the Bakken formation of the Williston Basin.
In these four case studies, the primary variable that affects the difference in long-term production of the different well groups is the percentage and amount of each proppant type used in the completion design. Completion and stimulation data was collected from public resources such as the North Dakota Industrial Commission (NDIC) database. In each case study, wells in the same field were grouped. For each group of wells, the average long-term production and economical effectiveness was analyzed.
The case studies in the Capa Field in Williams County North Dakota and the Chimney Butte Field in Dunn County North Dakota shows that over a 270 day period, in each group of wells completed with about 30 percent ceramic proppant mixed with silica sand, the wells produced an average of over 100 percent more than the comparable group of wells completed using only silica sand. The case study in the East Fork Field in Williams County North Dakota shows that after 270 days of production, the group of wells using 100 percent ceramic proppant attained an average of 27 percent production increase over the group of wells using an average of 62 percent ceramic proppant. These wells also attained a 67 percent production increase over the group of wells using an average of 35 percent ceramic proppant.
In comparing completion procedures in these high-producing fields, using a combination of high percentages and large amounts of ceramic proppant has yield higher production and EUR. The use of ceramic proppant not only covers the additional proppant cost in a short period of time, but also generates higher revenue in the long term. The findings from these case studies should apply to all fields that have similar reservoir characteristics.