Costin, Simona (Imperial Oil) | Smith, Richard (Imperial Oil) | Yuan, Yanguang (Bitcan Geoscience and Engineering) | Andjelkovic, Dragan (Schlumberger Canada) | Garcia Rosas, Gabriel (Schlumberger Canada)
Open-hole mini-frac tests are seldom performed in the Athabasca and Cold Lake oil sands due to the complexity of operations. In this paper we present the results of open-hole injections tests performed in Cold Lake, Alberta (AB), Canada. The objective of the injection tests was to assess the in-situ stress condition in the Cretaceous Colorado Group. The injection tests results combined with the run of formation image logs (FMI) before and after the injection have enabled not only the determination of the in-situ minimum stress in the rock, but also the full 3-D stress tensor, along with the orientation and inclination of the hydraulic fracture. The tests were performed in IOL 102/08-02-066-03W4 (N10 Passive Seimic Well, 'PSW'). The injection tests have revealed that the vertical stress in the area is the in-situ minimum stress, consistent with previous measurements. The hydraulically-induced fracture has sub-horizontal to moderate dip angle, mostly owing to the preexisting fabric of the rock, and peaks in the general NE-SW direction. Numerical modeling of the in-situ stresses has shown that the values of the vertical and the minimum horizontal stresses are close, with the vertical stress consistently being smaller than the minimum horizontal stress in all tested zones.
Analysis of mini-frac or, as commonly referred to in North America, Diagnostic Fracture Injection Tests (DFITs), have traditionally been the sub-discipline of completion & hydraulic fracture stimulation engineers. Conducting such tests has direct and indirect costs resulting from the test itself and the extended time required for the pressure falloff, that delays the completion of the well. The benefits must therefore outweigh the costs if the test is to be justified. The value is evident as these tests are performed regularly around the world as it is one of only a few processes that can help quantify within the same test both geomechanical properties and reservoir performance drivers.
The authors will present examples and lessons learned from regions around the world. In addition, the availability of a large quantity of public, high-quality data from oil & gas operators in Western Canada operating in shale and ultra-tight formations enable an assessment of the successes and failures of wellbore completions, reservoir types, and operator procedures. This treasure-trove of data will help completion engineers regardless of their basin of operations to overcome one of industries challenging questions "did the test achieve its objectives."
A successful waterflood can be implemented in a multi-layered tight oil reservoir developed with horizontal multi-fractured wells. This paper forecasts the recovery factor that can be achieved in such a reservoir as well as discusses the challenges of analyzing and modelling tight oil reservoirs developed with multi-fractured horizontal wells.
With some unconventional reservoirs that are hydraulically fractured, a phenomenon exists whereby material balance and simulation indicate pressure support from a water source that is not always obvious. This phenomenon is believed to be related to the multi-layered silts/shales in the reservoir and is not typically seen in simulation of conventional higher permeability reservoirs (Kair >10 mD). Although, the exact petrophysical nature of the silts/shale reservoir layers in this project are not well defined at this time, a successful production history match can be achived by incorporating their input into a simulation model.
Low to ultra-low permeability tight oil reservoirs have recently become a significant source of hydrocarbon supply in North America, Production and pressure transient analysis of tight oil reservoirs is one of the most difficult problems facing a reservoir researcher because of the extreme complexity inherent in tight formations, To produce oil and gas commercially from tight formations, naturally completed (open-holed) or cased horizontal wells with multi-stage hydraulic fractures are the most popular implementation for completion, and such kind of application is expected to create a complex sequence of flow regimes (
This paper provides a detailed discussion of numerical method of pressure transient and rate responses for hydraulically fractured horizontal wells in tight formation and compared with analytical (semi-analytical) methods based on the Bakken and Viking Formation in Western Saskatchewan. For Numerical simulated pressure transient responses, a naturally-completed (open-hole) and cased horizontal well with multiple transverse hydraulic fractures in a homogeneous or a sizable natural fracture system are considered. Numerical method for pressure and rate transient analysis is generated by employing a commercial reservoir simulator, CMG IMEX, a 3D finite-difference reservoir simulation package which is widely and popularly accepted by petroleum industry. As noted by many findings, it is shown that fully-filled and regional natural fractures would display various pressure transient characteristics and, hence, considerably affects well production performance. In addition, these conductive, interconnected natural fractures dominate the pressure transient performances of horizontal wells in tight formations even with the presence of hydraulic fractures. Additionally, the simulation runs also indicate that if the reservoir is naturally fractured to some extent, hydraulic fracturing stimulation might not improve productivity significantly, unless a large amount of hydraulic fractures and infinite conductivities can be achieved. To demonstrate the feasibility of numerical simulation models, there is a representative contrast between numerical and analytical (semi-analytical) methods. To demonstrate the feasibility of numerical simulation models, there is a representative contrast between numerical and analytical (semi-analytical) methods.
Siddiqui, Shameem (Halliburton) | Dhuldhoya, Karan (Halliburton) | Taylor, Robert (Halliburton) | Dusterhoft, Ronald (Halliburton) | Hards, Eric (Halliburton) | Niebergall, Greg (Yoho Resources) | Stobo, Barry (Yoho Resources)
Evaluating unconventional reservoirs presents several challenges because of a lack of modeling tools that can properly capture inherent heterogeneities and variable reservoir attributes. This paper discusses the development of a workflow for modeling complex fracture networks in hydraulically fractured horizontal wells and then subsequently validating them through the use of production-history matching with an unstructured grid-based simulation. In reservoirs with low stress anisotropy, stimulation generally creates fracture networks and induces fractures that can have varying orientation. During reservoir simulation, these fractures have typically been depicted as planar, orthogonal, bi-wing fractures for the simplicity of gridding, even though it is known that these planar models do not adequately describe the overall complexity of the induced fractures. These complex fracture network models can only be truly represented in a simulation model through the use of unstructured grids.
In developing the workflow, a complex fracture network modeling tool that takes into account microseismic or image log data, as well as pressure and treatment data, was used to create and calibrate complex fracture networks. These were incorporated into an unstructured grid-based reservoir simulation model, which also included pressure-volume-temperature (PVT), rock and fluid, and completions data, as well as attributes from an earth model for the area. Nodal analysis software was used to generate the bottomhole pressure (BHP) from wellhead pressure (WHP) and production rate data for history matching.
Results from simulation models with hydraulic fractures having similar orientation and dimensions in the structured and unstructured grids showed a very good match and gave confidence in the use of unstructured gridding to help ensure reservoir simulation. Several complex fracture designs with the unstructured grids were used during history matching. Fracture properties, such as propped fracture half-length, fracture conductivity, number and spacing of existing natural fractures, and natural fracture conductivity, were varied to determine the most representative models for the fractured reservoir based on production rates. Results showed that natural fractures were present in the stimulated reservoir volume. However, the closest matches were achieved with secondary/natural fractures having very low conductivity. The evidence suggested that the natural fractures in the reservoir were not being adequately stimulated and that a combination of finer proppants, fluid diversion, or other completion or treatment design changes might have resulted in increased production through better connection with the natural fractures.
Complex fracture modeling and history-matching validation with unstructured grid-based reservoir simulators is a relatively new process, and this paper demonstrates its potential for optimizing fracture design and treatments by correlating a given treatment to the representative fractured reservoir model. Initial work performed with this workflow provided information that has enabled significant design changes, with encouraging production results. Continued work in this area of technology is now being performed to help understand reservoir, fracture, and fluid interaction to enhance drilling and completion practices based on specific reservoir conditions.
Ziarani, Ali S. (Trican Well Service Ltd.) | Chen, Cheney (Trican Well Service Ltd.) | Cui, Albert (Trican Geological Solutions) | Quirk, David James (Trican GeoTomo Microseismic) | Roney, Dana (Lone Pine Resources)
Horizontal wellbore drilling and completion technology with multi-stage fracturing has revolutionized the exploitation of unconventional resources in North America in recent years. Many unconventional oil and gas reservoirs with ultra-low permeability have become economical as a result. Yet, the development and completion costs of these resources can be further improved by optimizing the number of fracture stages placed on each wellbore and the number of wellbores drilled per section of land.
This study highlights our operational and analytical experience on an integrated workflow for optimization of fracture and wellbore spacing to develop the unconventional resource in Western Canadian Sedimentary Basin. The study is based on fracturing design and optimization, microseismic fracture mapping, reservoir modeling and production analysis for over 30 case studies on different formations in Canada including Montney, Cardium, Doig, Beaverhill Lake, Viking, and Sprit River formations.
The typical workflow for fracture and well spacing optimization studies includes multiple and iterative steps: minifrac tests, fracture modeling and calibration, fracture job execution, microseismic monitoring, reservoir simulation and production data analysis. In this integrated process, hydraulic fracture models were built based on fracture job data, rock mechanics and log data, and then calibrated with minifrac data and microseismic fracture mapping results. Three dimensional reservoir simulation models were constructed using laboratory core data, petrophysical and geological data, and reservoir fluid PVT properties. The calibrated fracture models were integrated into reservoir simulation models. The reservoir models were fine-tuned by history matching the production data. The fine-tuned models were then used to run multiple scenarios by varying the number of fracturing stages per wellbore and wellbores per section. Fracturing treatments with different pump rate, proppant size, pumping schedule and proppant tonnage were further investigated to optimize fracture geometry and conductivity for production enhancement. Optimal fracture and wellbore spacing scenarios were recommended for future drilling and completion planning in the field.
Such optimization studies have helped to minimize operation cost and improve the economics of resource development. Our workflow and experience in West Western Canadian Sedimentary Basin can be a useful guideline to improve economic success of unconventional resources in other basins around the world.
Co2 relative permeability is a critical parameter affecting many aspects of Co2 injection for Enhanced Oil recovery and Co2 storage including; injectivity and trapped phase saturation.
In this study, we use measured Co2 - brine relative permeability data available in the literature to study the behaviour of the data obtained for various rocks. These measured Co2 relative permeabilities show large variations in the values of relative permeability and also in the trend of the relative permeability curves.
We identify the rock internal structure or quality as a controlling factor with considerable impact on Co2 relative permeability and we offer an explanation for the observed variation in Co2 relative permeability behaviour. We use a pore network model with different pore and throat distributions to verify the effect of rock pore and throat distributions on Co2 relative permeability. Based on our definition, a normal pore-throat distributions with similar connection produces a regular Co2 relative permeability curve shape which gives a high Co2 injection rate whereas in an abnormal pore-throat distribution with dissimilar connection, it is observed that the Co2 relative permeability curve shape is almost vertical .
We extended the work to the investigation of the impact of the rock internal structure on the Co2 injection characteristics particularly on Co2 injection rate. We found that normal pore-throat distributions with similar connection result in much higher Co2 injection rate than do the abnormal pore-throat distributions with dissimilar connection.
The results of this study will allow us to identify rocks that would be more suitable for Co2 injection (e.g., higher injectivity requiring lower number of injection wells) on the basis of the structure and distribution of the pores inside the rock.
Introduction and Objective.
In most petroleum engineering literatures, the relative permeability of Co2 has been studied for each formation separately and the main factors considered to affect the Co2 relative permeability are; fluid saturation, hysteresis and interfacial tension. As for a group of formations with different rock types, the difference in Co2 relative permeability curves is mainly attributed to rock type parameters. However, it has been found that even in a set of samples extracted from different formations in the same rock type or from a single formation, there is diversity in Co2 relative permeability curves. Rock pore structure or quality has been assumed to be responsible of the observed disparity, but no detailed explanation has been offered as to how it could results in different Co2 relative permeability curves for a set of formations in the same rock type. In this work, we are introducing an improved concept of pore and throat distribution, which will be used to interpret the observed differences in Co2 relative permeabilities.
Slick water hydraulic fracturing treatments are the preferred method for stimulation of tight hydrocarbon plays as these treatments enhance the complexity of fracture networks, increase fracture lengths, reduce formation damage and decrease treatment costs. These characteristics of a slick water treatment are critical to produce economic wells in unconventional formations. Even though these treatments are effective, they also have disadvantages that can limit production and increase treatment costs. With slight modifications to the treatment design of traditional slick waters - the addition of a novel chemical and 5% nitrogen - the limitations can be reduced.
The performance of the slick water treatment is improved by modifying the proppant's surface properties. A novel surfactant preferentially adsorbs onto the surface of the proppant (for both quartz and ceramic), hydrophobically modifying the surface of the solids. The enhanced surface properties create an attraction between the proppant surface and nitrogen gas, in effect, surrounding the particle with a thin layer of gas and thus increasing the buoyancy of the proppant in water. These enhanced properties allow for improved proppant distribution, deeper proppant penetration within the complex fracture network, increased proppant pack volume, and increased maximum proppant concentration that can be placed. Improving proppant placement and increasing the volume that the proppant occupies within the fracture enhances the conductivity of the fracture network, therefore improving the productivity of the well.
Laboratory studies of polymer adsorption, sand pack column flow analysis, crush resistance and brine compatibility testing will be presented to complement laboratory analyses previously published. Case studies of field treatments will also be provided. The first case study uses pad wells and compares the new system to traditional fracturing fluids. It will show that, without changing any other variables in the treatment design, production is enhanced significantly. The other two case studies will illustrate how production has been increased in two formations in the Western Canadian Sedimentary Basin.
Norris, Stephen O (Anadarko Petroleum Corp) | Scherlin, John Michael (Anadarko Petroleum Corp) | Mukherjee, Joydeep (Dow Chemical Co.) | Vanderwaal, Paul (Dow Chemical Company) | Abbas, S. (Dow Chemical Company) | Nguyen, Quoc Phuc (University of Texas At Austin)
In a previous paper we described the laboratory work, reservoir simulation, and initial design of a CO2 Foam Pilot in the Salt Creek Field, Natrona County, WY. In this paper, we review the diagnostic testing and initial results from the pilot including: injection rate profile, production data analysis, injection and production logging, chemical tracers, streamline analysis, and reservoir simulation.
Although the CO2 flood has been very successful at Salt Creek, it is recognized that certain isolated patterns have exhibited high CO2 production and inefficient CO2 utilization, most likely due to the channeling of fluids through high permeability, low volume zones (fractures, thief zones, etc.) and the gravity over-ride of the injected fluids. Accordingly, a foam pilot was initiated to test the ability of CO2 to remediate these conditions.
A change in the injection well rate (at constant surface injection pressure) was the first indicator to be observed; the injection rate decreased by approximately 40%, indicating a strong mobility reduction of the CO2 in the reservoir. Production and injection profile logs were run before and after surfactant injection, and a change in profile was observed in one producer. Chemical tracers were injected in both the gas and water phases before and after surfactant injection; results indicate that CO2 was diverted from high permeability, low volume conduits, such as fractures. An analysis of the production data for the four offset producers show a definite increase in liquid production and a corresponding decrease in GLR (gas-liquid-ratio.) Streamline analysis suggest areal diversion of CO2 over time. Finally, reservoir simulation prediction cases are given and discussed.
CO2 flooding has become a standard EOR technique for many water-flooded fields. Methods for increasing the efficiency of these floods, such as the use of CO2 foam, can add great value.
The Salt Creek Field in Natrona County, WY, has undergone CO2 injection since 2004. The field has been developed in phases along the flank of the reservoir, where the minimum miscibility pressure is less than the parting pressure of the formation. To date, over 25 MMSTB of oil have been recovered in this tertiary process. Daily CO2 injection is approximately 675 MMcf/D at an average WAG (water-alternating-gas) ratio of 1:3, and the current oil production rate is approximately 13,500 STB/D. Although the flood been very successful, it is recognized that certain isolated patterns have exhibited high CO2 production and inefficient CO2 utilization, most likely due to the channeling of fluids through high permeability, low volume zones (fractures, thief zones, etc.) and the gravity over-ride of the injected fluid. A CO2 foam pilot was undertaken to see if these conditions could be remediated.
Gendrin, A. (Schlumberger Carbon Services) | Sosio, G. (Schlumberger Carbon Services) | Miersemann, U. (Schlumberger Carbon Services) | Adushita, Y. (Schlumberger Carbon Services) | Pekot, L. (Schlumberger Carbon Services) | Desroches, J. (Schlumberger Carbon Services) | Andrés, Roberto (Endesa Generación) | González, Pedro (Endesa Generación) | Giménez, Antonio (Endesa Generación) | Ballesteros, Juan Carlos (Endesa Generación)
Building a reliable yet cost-effective monitoring plan that all interested parties have faith in is a key challenge in carbon dioxide (CO2) geological storage projects. Several objectives need to be achieved: accurate CO2 and pressure front tracking, CO2 follow up in case of migration outside the primary reservoir. Many constraints need to be taken into account: legislation, geology, risks, costs, public perception. We present the scheduled monitoring plan of a candidate site in Spain, where 42 million tons of CO2 are planned to be injected over 30 years. The reservoir consists of high porosity/high permeability sandstone with some alternating shale packages, ~200 m thick, located at ~2200 m depth. It is overlaid by a carbonate formation, the secondary reservoir, and by a shaly primary seal. The secondary seal, mainly shaly with some alternating sand beds, goes almost up to surface.
When beginning a CO2 geological storage project, one of the first steps is to conduct a feasibility study for several monitoring technologies, since the reservoir characteristics of each site can affect their performance. It is found that detectability of seismic signal will be challenged by the small values expected for CO2 saturations. However, subtle surface deformation will be easily detectable by satellite technologies. Repeat neutron well logging is also found to be appropriate. Based on these considerations, five deep monitoring wells, with time-lapse neutron logging, are proposed as the basis of the monitoring plan. Surface deformation and micro-seismic measurements will strengthen the understanding of the storage site.