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.
Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.
The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.
One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.
The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.
SPE awards recognize members for their technical contributions, professional excellence, career achievement, service to colleagues, industry leadership and public service. This year the Canada Region recognizes 14 well-deserving members who have contributed exceptional service and leadership within SPE, as well as making significant professional contributions within their technical disciplines. The SPE Regional Service Awards acknowledges exceptional contributions to SPE at the section or regional level and recognizes singular devotion of time and effort to the programs and development of the member’s section. Daniel “Blair” Fisher is currently the Manager of Field Engineering at Sanjel Energy Services Inc. He is proudly one of the founding employees from May 2016.
Nigeria has vast amount of gas and gas-condensate resources that have not been developed because of country’s traditional focus on oil reservoirs in the past. However, country is now embarking on a systematic development of gas resources. Objective of this study is to discuss issues being faced by all parties to evaluate gas resources and practical solutions to move forward with gas development on a large scale.
This paper discusses commercial (including team dynamics), technical, data analysis, and organizational capability issues relevant to development planning for gas fields. Practical solutions such as open and full communication among all stakeholders, due diligence to locate and analyze technical data, and proper bench-marking and testing of relevant recovery mechanisms in commercial software packages are proposed that would lead to proper evaluation of gas resources. It is emphasized that work alignment to resolve uncertainties and reach appropriate decisions is absolutely critical for project success. While practical solutions presented in this paper are especially geared toward gas field development, many of these thoughts and concepts are applicable for technical analysis of all petroleum engineering projects.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohi bited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. However this perception is changing, in particular due to field results obtained from a number of chemical EOR pilots or full field floods implemented in Canada in higher viscosity oil in the past few years. Canada is a country well-known for its heavy oil production; recovery processes such as Cold Heavy Oil Production with Sand (CHOPS) and Steam Assisted Gravity Drainage (SAGD) have been invented there. However cold production is limited in terms of the level of recovery it can achieve and thermal techniques also have limitations in particular when reservoirs are thin. Thus Canadian companies have been pursuing chemical EOR to increase recovery in those types of reservoirs. The aim of this paper is to review some of the Canadian projects for which public information is available. Several mostly unpublished projects will be discussed in details, and conclusions will be drawn on the applicability of chemical EOR methods in heavy oil. The practical experience gained in Canada can be applied in other regions of the globe where chemical EOR has so far not been considered or has been screened out because of high viscosity. Introduction Canada is well known for its heavy oil and bitumen reserves; most of the bitumen reserves are exploited using thermal methods such as cyclic steam stimulation or Steam-Assisted Gravity Drainage (SAGD), while heavy oil is exploited mostly using cold production methods such as CHOPS (Cold Heavy Oil Production with Sand). Cold production has been reviewed extensively by other authors and will not be addressed in this paper but in general it only leads to less than 10% OOIP recovery. Thermal methods are not always applicable, in particular when the pay is thin and in that case alternatives are required to increase recovery beyond that number; chemical EOR is such an alternative.
The Suffield Caen reservoir contains 17?API heavy oil and the pool has been under waterflooding since 1996 with water cut of 96%. Primary and secondary oil recovery is 15 ? 20% of OOIP. A major problem encountered in waterflood was poor sweep efficiency and high water cut caused by high water/oil mobility ratio, as water quickly broke through the reservoir owing to fingering effects. It is known that sweep efficiency during waterflood can be improved significantly by increasing the viscosity of injected water by use of polymer solution, thus generating a more favorable mobility ratio and enhancing oil recovery. The results of reservoir simulation studies suggested that polymer flood would achieve incremental recovery factor of 7 ? 12%, and coreflood results indicated that 29 ?32% of incremental recovery is achievable by 0.5 pore volume (PV) of polymer injection.
Core floods including polymer, surfactant/polymer(S/P) and alkali/surfactant/polymer (A/S/P) were conducted through lab experiments and eventually polymer flood was selected as a pilot project to improve oil recovery for the Caen reservoir on the basis of polymer, S/P and A/S/P core flood results and project economic evaluation.
Polymer injection started in the reservoir 15 months ago and a very positive response has been seen as oil cut has increased to 10% from 5% and oil production rose to 600 bbl/d from 400 bbl/d. Therefore, the polymer flood pilot project is continually implemented and the polymer flood is planned to extend to similar reservoirs in the Suffield area.
There is a large amount of conventional heavy oil resaves in the West Canada Basin, so far the primary recovery factor is only 10%, there is a big potential to enhance oil recovery by polymer flood. This polymer flood pilot project provides valuable experiences and guidance to field application.