In this paper a laboratory study was reported for investigating a method to improve sweep efficiency by applying alkaline flooding for Pelican Lake reservoir. This included interfacial tension measurements, micromodel observatios and channelled sandpack flood tests. In total, 48 flood tests were conducted in channelled sandpacks to evaluate the chemical formulas and injection strategies for Pelican Lake oil. The first 14 sandpack flood tests were carried out to assess the potential of the alkaline flooding for the oil. The results suggested that 0.4 wt% NaOH and 0.2 wt% Na2CO3 was the optimum combination to maximize the oil recovery efficiency in the channelled sandpacks. Based on industry interest in using a NaOH-only slug injection, in the second step 34 flood tests were conducted with the injection of only NaOH solution. For Pelican oil, 0.6 wt% NaOH was the optimum concentration to maximize the oil recovery efficiency (~15% IOIP recovery) in NaOH-only injection. The sandpack flood results obtained in this study showed that formation of water-in-oil dispersion and improvement of sweep efficiency in channeled sandpacks did occur in the tertiary recovery process through the injection of NaOH-only solution.
This paper deals with the need to determine the optimum solution for the removal of hydrocarbons in frac flow back fluids on wells completed in unconventional resource areas. These include wells in the Barnett, Eagleford and Marcellus Shales. Fracture stimulation fluid volumes of up to 14 million gallons per well are becoming common. A significant portion of that water returns to the surface as a contaminated waste. To reduce cost and lower the environmental impact of managing such production, companies are seeking to treat and re-use fluids during development of the field.
This project looked at several methods to remediate the produced hydrocarbons to allow reuse of the fluids in other treatments. Our investigations included testing of removal techniques and the concomitant analytical methodology to use in field operations to ensure proper performance of the technologies. Tests were performed with actual field produced brines with five different filter medias including samples that can be regenerated as an alternative to absorbent materials that require replacement or regeneration to continue operation. Pre-treated fluids were then processed through subsequent membranes and purification to make them suitable for re-use. Results from this work have allowed our program to develop more efficient removal treatments and more reliable analytical methodology providing better field level guidelines for commercial operations.
The Revolution in Well Fracturing to Develop Gas Shale Resources
Fracture stimulation of oil and gas reservoirs has been an ongoing operation for decades. The use of oil, water and other materials as proppant transport has been covered extensively for their ability to create, extend and enhance the productivity of wells.
Shale formations have laminated structures which result in significant differences in mechanical properties along the orientations parallel to and perpendicular to laminations (bedding planes). These differences lead to anisotropic horizontal stresses. Failure to consider the effect of anisotropic behavior of shale can have severe consequences for drilling. In rocks with anisotropic mechanical properties and strength, there is a high risk of wellbore instability while building deviation angle from vertical sections. Conventional wellbore stability analysis approaches do not consider material anisotropy and laminated nature of shales, which can result in underestimated stresses leading to incorrect safe trajectory or mud-weights.
Shale formations in the Horn River Basin (HRB) are strongly anisotropic with anisotropic ratios varying from 1.2 to 3.5. In this paper, the authors demonstrate the importance of considering anisotropy in estimation of in-situ stresses and wellbore stability analysis. Two field case study examples are presented to underscore the consequences of neglecting anisotropy in wellbore stability analysis.
The Horn River Basin (HRB), the largest shale gas field in Canada, is located in northeastern British Columbia of the Western Canadian Sedimentary Basin (WCSB). It is overlain by the Fort Simpson Formation and underlain by the carbonates of the Lonely Bay Formation, Nahanni Formation or Pine Point Formation. Multi-laterals (horizontal drilling) with multistage hydraulic fracturing are typically used in the HRB. Major drilling challenges in the area include borehole instability due to sloughing, tight hole, stuck pipe, excessive reaming leading to large wellbore breakout/washout, and moderate to severe
lost circulation or combination of any of these problems. One of the most troublesome formations is Fort Simpson shale which is about 800-1000m thick [Ross and Bustin, 2008] reactive high clay content shale which swells when contacted by fresh water and usually consist of high pressure zones. To avoid these types of wellbore instabilities, an intermediate casing string is typically set right after passing through the Fort Simpson shale [Stewart et al. 2000] or before entering Muskwa. In this paper, the authors analyzed some of the wellbore instability problems encountered in the HRB and identify possible causes of these problems.
The term shale is normally used for the entire class of fine grained sedimentary rocks that contain substantial amount of clay minerals [Lal, 1999]. Organic-lean Fort Simpson shales are clay rich, with almost equal concentrations of illite, kaolinite, and chlorite [Ross and Bustin, 2008]. It is Devonian age, weak, brittle shale and calcareous silty laminated with high quartzitic content [Stewart et al. 2000]. Shale is formed of platy type of grains when it is compacted, the grains are usually distorted and elongated in one or more directions, and aligned in parallel to sub-parallel orientation, making it a layered material. Thus, shale formations have laminated structures in the form of bedding, layering, stratification, fissuring which combined with insitu stresses result in directionally dependent rock properties. Because of this reason, shales are said to be inherently anisotropic. When the properties of a material are the same in all directions, the material is said to be isotropic. On the contrary, when the properties of a material vary with different orientations, the material is said to be anisotropic.
We introduce the concept of Fracture Treatment Optimization (FTO) to find and analyze the Point of Diminishing Return (PDR) of stimulations. The approach is based upon locating the opening and closing points of fractures as identified through Seismic Moment Tensor Inversion (SMTI) analyses of microseismic data collected during treatments. By using SMTI data, it is postulated that the size of a treatment, the proppant concentrations and amounts, types of fluid pumped and amounts, the rates of treatment, and disposition of the fracture network may be analyzed to determine if they are optimal for the formation and the stress conditions of each individual fracture stage. As described, FTO is performed as a post-treatment approach to characterize the effectiveness of the treatment process. The PDR is identified by analyzing the SMTI data for each event in time and compared to the fracture treatment data. We show, through example, how the SMTI data can be used to establish when the transition between fractures with opening components of failure and those including significant closure components of failure. We suggest that these states are indicative of reaching a PDR thereby allowing for changes to the treatment to be considered. In the examples provided, we identify apparent PDRs due to leakoff dominated pad stages which are too large and when proppant is added too late in the stage. Additional PDRs are identified in the treatment when an energy balance has been reached, where leakoff and fluid injection is at equilibrium. At this point we suggest that introducing a change in energy or proppant concentrations can optimize the treatment. This empirical optimization allows for potentially more economic and efficient stimulations in subsequent hydraulic fracture treatments in the field.
This paper presents results of an experimental study that systematically examined the propagation of nanodispersed catalyst suspension in sand packs at Athabasca reservoir conditions. The concentration and size distribution of the particles at the injection and production end were measured. The pressure drops in different segments along length of the sand pack were monitored continuously. The retention behavior of particles at the end of each experiment was examined by measuring the catalyst concentration in the bed as a function of the distance from injection end of the sand pack and also by analysis of extracted samples using scanning electron microscopy.
This research is a part of a large multidisciplinary effort aimed at developing a nanoparticles based process for in situ upgrading of heavy oil by catalytic hydrogenation during thermal recovery processes. An essential element of such in situ upgrading is the placement of nanodispersed catalyst particles deep into the formation where it can accelerate the high temperature upgrading reactions. Therefore, an understanding of the propagation behavior of nanoparticles in reservoir sand is essential for developing such technology. The results of this work would also be useful for modeling any other process involving transport of nanoparticles through porous media.
The results show that it is possible to propagate the nanodispersed catalyst suspension through sand beds without causing permeability damage but a small fraction of the injected particles are retained in the sand. It was found that much higher retention occurs in the entrance region of the bed and such retention was higher in the Athabasca sand beds than in clean silica sand with the same flow and suspension properties. A modified deep bed filtration model was developed to history match the macroscopic propagation behavior of suspended particles in sand beds.
To best of our knowledge, this is the first experimental study on transport of nanoparticles dispersed in viscous oil through sand beds. It provides valuable information on propagation and retention behavior of nanoparticles. Considering the rapidly rising use of nanoparticles in industry, such transport will be encountered in many industrial applications and environmental problems.
Turner, Mark George (EnCana Oil & Gas USA Inc.) | Weinstock, Coleby Thomas (EnCana Oil & Gas Co. Ltd.) | Laggan, Michael James (Schlumberger) | Vogel, Matthew (Schlumberger) | Rondon, Janz (Schlumberger) | Bogdan, Andrey (Schlumberger) | Pena, Alejandro Andres (Schlumberger)
The Channel Fracturing technique was introduced for multi-stage well stimulation in the Jonah Field in 2010. 622 stages have been pumped with this novel technique since. Production increases by as much as 27% (Johnson et al., 2011) realized over conventional completion methodologies. In this previous study, each stage was flowed back immediately after each treatment.
The successful introduction of the Channel Fracturing technique prompted a new attempt to optimize completion practices by eliminating immediate flowback of each stage as a necessary step to sustain production performance goals (Cramer, 2008). A field study was conducted to evaluate the performance of five new wells stimulated with the Channel Fracturing technique combined with sequential fracturing treatments without flowback in between stages. Gas production, fluid flowback and treating pressure data was gathered and compared against a sample of 18 offset wells stimulated with conventional proppant placement with immediate flowback after each stage.
Results indicate that the Channel Fracturing technique increased production by up to 28% with respect to the control group. Production gains were obtained without the occurrence of screen-outs for the wells stimulated with Channel Fracturing. Improvements in operational efficiency due to continuous fracturing operations and avoidance of screen-outs led to a reduction in overall operational costs of 18%. Results show that the combination of Channel Fracturing with sequential stage stimulation within a single wellbore can mitigate previously documented production performance issues, reduce operational logistics and reduce the overall impact to the hydraulic fracturing footprint. By virtue of these benefits, well stimulation via multi-stage Channel Fracturing without flowback in between stages has been adopted as a completion practice of choice for wells in the Jonah field.
Many Steam Assisted Gravity Drainage (SAGD) optimization studies published in the literature combined numerical simulation with graphical or analytical techniques for design and performance evaluation. There have been numerous efforts that integrated the simulation exercise with global optimization algorithms. Some studies focused on optimization of cumulative steam-to-oil ratio (cSOR) in SAGD by altering steam injection rates, while others focused on optimization of
cumulative net energy-to-oil ratio (cEOR) in solvent-additive SAGD by altering injection pressures and fraction of solvent in the injection stream. Several studies also considered total project net present value calculation by changing total project area, capital cost intensities, solvent prices, and risk factors to determine the well spacing and drilling schedule. Optimization techniques commonly used in those studies were scattered search, simulated annealing, and genetic algorithm (GA). However, the applications of hybrid genetic algorithm were rarely found.
In this paper, we focused on optimization of solvent-assisted SAGD using various GA implementations. In our models, hexane was selected to be co-injected with steam. The objective function, defined based on cumulative steam-oil ratio (cSOR) and recovery factor, was optimized by changing injection pressures, production pressures, and injected solvent-tosteam ratio. Techniques including orthogonal arrays (OA) for experimental design (e.g. Taguchi's arrays) and proxy models
for objective function evaluations were incorporated with the GA method to improve computational and convergence efficiency. Results from these hybrid approaches revealed that an optimized solution could be achieved with less CPU time (e.g. fewer number of iterations) compared to the conventional GA method. Sensitivity analysis was also conducted on the choice of proxy model to study the robustness of the proposed methods.
To investigate the effects of heterogeneity in the design process, optimization of solvent-assisted SAGD was performed on various synthetic heterogeneous reservoir models of porosity, permeability, and shale distributions. Our results highlight the potential application of the proposed techniques in other solvent-enhanced heavy oil recovery processes.
For stratified reservoirs with free crossflow and where fractures do not cause severe channeling, improved sweep is often needed after water breakthrough. For moderately viscous oils, polymer flooding is an option for this type of reservoir. However, in recent years, an in-depth profile modification method had been commercialized where a block is placed in the high-permeability zone(s). This sophisticated idea requires (1) the blocking agent must have a low viscosity (ideally a unit-mobility displacement) during placement, (2) the rear of the blocking-agent bank in the high-permeability zone(s) must outrun the front of the blocking-agent bank in adjacent less-permeable zones, and (3) an effective block to flow must form at the appropriate location in the high-permeability zone(s). Achieving these objectives is challenging but has been accomplished in at least one field test. This paper asks: When is this in-depth profile modification process a superior choice over conventional polymer flooding?
Using simulation and analytical studies, we examined oil recovery efficiency for the two processes as a function of (1) permeability contrast, (2) relative zone thickness, (3) oil viscosity, (4) polymer solution viscosity, (5) polymer or blocking-agent bank size, and (5) relative costs for polymer versus blocking agent. The results reveal that in-depth profile modification is most appropriate for high permeability contrasts (e.g. 10:1), high thickness ratios (e.g., less-permeable zones being 10 times thicker than high-permeability zones), and relatively low oil viscosities. Because of the high cost of the blocking agent (relative to conventional polymers), economics favor small blocking-agent bank sizes (e.g. 5% of the pore volume in the high-permeability layer). Even though short-term economics may favor in-depth profile modification, ultimate recovery may be considerably less than from a traditional polymer flood.
Multiple, mechanically-activated, sliding-sleeve fracports is a common completion used for horizontal wells in unconventional reservoirs. Characteristic seismic signals have been observed at approximately the same time as pressure spikes associated with balls dropped to open the sliding sleeves. The ‘ball drop' seismic signals are high amplitude, low frequency, multiple discrete events with a short period of time, with each event locating at the fracport. The seismic radiation
characteristics are consistent with an axial displacement along the treatment well. The seismic signals are attributed to the sleeve sliding open, which results in sufficient energy to account for the high amplitude signals. The occurance of the ball drop events can therefore be used to diagnose if the ball seated and the sleeve opened at the expected location, and along with the pressure and microseismic response can be used to validate the expected actions of the completion. Several case studies are also presented illustrating successful stage isolation with proper completion operation, response of the sleeve not opening properly and stage overlap associated with both hydraulically connected fracture networks in the reservoir and connected fracture ports.
This paper discusses a modeling technique that can be used to predict the gas production from Marcellus Shale wells. The fundamental concept is to model the relationship between pressure and production over time using inflow performance relationships and volumetric calculations. The model can be adjusted to fit the production values and then used to predict production on that well or on offsetting wells based on the pressures that are expected.
The introduction of this paper provides a general description of the characteristics and production volumes that are typical of horizontal Marcellus wells.
The theory separates the reservoir into two systems; the stimulated reservoir and the matrix reservoir. From these systems inflow performance relationships, decline curves, and volumetric calculations are used to build the model. Over time, the inflow performance curves will change. With this model, an inflow performance curve can be generated at any point in the life of the well.
By creating a model for a well, a prediction can be made of the well's production if conditions change. This could be extremely helpful in modeling pipeline and compression systems or evaluating wells under changing conditions. It can also be used to estimate potential production from curtailed wells. Over time, the model may also be used to indicate if damage or enhancements have occurred or if chemical, mechanical or stimulation treatments were effective.
The technique could easily be applied to other similarly designed wells. This could include other shale wells, CBM wells or wells in naturally fractured reservoirs.
This paper presents a theory that is a "first run?? concept, based on previous work, theories, and observations. The technique presented can be expanded and refined by future researchers.