One major drawback in the implementation of CO2/surfactant enhanced oil recovery is the high cost of the surfactant volume needed and the extrapolated amount of surfactant required for use in the field. Therefore, there exists a need for a methodology to evaluate the most economic surfactant volume that will lead to optimum oil production.
This paper presents the results of laboratory experiments that were designed to study the performance of foam injection and to obtain information on the parameters that will be utilized in a future modeling study to determine the minimum but most effective volume of surfactant needed for optimum foam generation and hence oil recovery in a porous medium. The effect of reservoir pressure and surfactant concentration is studied.
Carbon dioxide and surfactant solution were co-injected into Berea sandstone core that was saturated with brine and oil after a waterflood process. Some of the values of parameters utilized in the experiments include surfactant concentrations of 0.1 wt % and 0.5 wt %, average back pressure of 2350 psi and total flowrate of 0.4 cm3/min, with CO2 injected at 0.3 cm3/min and surfactant concentration at 0.1 cm3/min, which results in a volumetric flow ratio of 3:1 and foam quality of 75%.
Results show that at a higher surfactant concentration, more oil was recovered, and a steady increase in pressure difference was observed. This indicates that foam was formed, which was also seen at the production end of the system. The foam created during the experiments with the 0.1 wt % surfactant concentration, on visual inspection, appeared to be weaker than that formed in the case of the 0.5 wt % concentration.
Takeshita, Yukitoshi (NTT, NTT Energy and Environment Systems Laboratories) | Kamisho, Takuya (NTT, NTT Energy and Environment Systems Laboratories) | Sakata, Seizo (NTT, NTT Energy and Environment Systems Laboratories) | Sawada, Takashi (NTT, NTT Energy and Environment Systems Laboratories) | Watanuki, Yoshikazu (NTT Advanced Technology) | Nishio, Ryuichi (NTT Advanced Technology) | Ueda, Toshinobu (NTT Advanced Technology)
Lost circulation (LC), complete loss of drilling fluids into subterranean formations through natural/induced fractures, is a recurring problem costing the industry millions of dollars annually. Numerous solutions and drilling practices are applied in the field to mitigate, prevent or cure LC. Among these, the application of lost circulation materials (LCM) in the drilling fluids for plugging flow paths has been a widely accepted practice. LCM like ground marble, graphitic carbon and fibers are well-known to the industry. Different outcomes have been reported in laboratory tests and field applications when LCM is used in aqueous drilling fluids (AF) as opposed to non-aqueous drilling fluids (NAF). The present work provides a novel rheological tool to distinguish plugging performance of fiber-laden LCM in AF and NAF.
The LCM plugging performance is determined by conducting tests on permeability plugging apparatus (PPA) using a tapered slot (TS) on combination of fibers and particulates like ground marble and resilient graphitic carbon. It was observed that several combinations of fibers and particulates formed a plug in TS with minimal fluid loss in aqueous drilling fluids; however, when tested in NAF, LC was difficult to control.
To investigate the above performance difference, tests were conducted with an Anton Paar rheometer. Rotational rheometry is performed to measure first normal stress difference (N1) at low and moderate shears. It is found that the fiber contribution towards N1 in aqueous fluids is remarkably different from that in NAF. Microscopically, this difference in N1 could be attributed to the distinct fiber properties and orientation in these two systems that explain their contrasting performance in PPA analysis. Thus, the rheological technique provides a tool to identify LC control ability of the fiber-laden LCM system and optimize the concentration of fibers and LCM during the planning phase of drilling fluids.
Energy efficiency is a metric of relative performance, to either a benchmark or plant specific baseline. As such, these metrics are an integral component of energy and carbon management practices. This paper presents an approach used by Energy Star to implement manufacturing plant energy benchmarking, or Energy Performance Indicators (EPI), for a variety of industries.
To date, EPI have been developed for industries ranging from "light?? manufacturing such as auto assembly and food processing to "heavy??, energy intensive sectors like cement, glass, and paper. Since "all plants are different,?? the EPI control statistically for differences between plants including product mix, climate, utilization, and vertical integration. After adjusting for differences between plants the EPI statistically "scores?? plants from 1 to 100 in terms of their percentile ranking. When characteristics change within a plant over time, these EPI can also be used to construct adjusted energy baselines.
This paper describes the approach used for developing the EPI. It compares the results for 10 industries, in terms of the types of variables that are included and the range of performance, measured by the inter-quartile range. The paper gives an example from pharmaceuticals of how the EPI can be applied to create adjusted baselines, in this case normalizing for year to year differences in weather. The paper provides examples of how the distribution of performance has changed over time for auto assembly and cement manufacturing. The range of performance for both sectors has narrowed, contributing to an industry wide reduction in energy and carbon.
Since Energy Star for Industry was launched, the number of EPI in use or under development has grown to 19 sectors within 11 industries. Until now, no industry-wide, plant-level, energy benchmark previously existed for these industries. We find that every industry has plant specific factors that influence energy consumption, so that a measure of energy efficiency must account (normalize) for those differences to be a useful management tool.
The flow of two or more immiscible fluids in porous media is ubiquitous particularly in oil industry. This includes secondary and tertiary oil recovery, CO2 sequestration, etc. Accurate predictions of the development of these processes are important in estimating the benefits, e.g., in the form of increased oil extraction, when using certain technology. However, this accurate prediction depends to a large extent on two things; the first is related to our ability to correctly characterize the reservoir with all its complexities and the second depends on our ability to develop robust techniques that solve the governing equations efficiently and accurately. In this work, we introduce a new robust and efficient numerical technique to solving the governing conservation laws which govern the movement of two immiscible fluids in the subsurface. This work will be applied to the problem of CO2 sequestration in deep saline aquifer; however, it can also be extended to incorporate more cases. The traditional solution algorithms to this problem are based on discretizing the governing laws on a generic cell and then proceed to the other cells within loops. Therefore, it is expected that, calling and iterating these loops several times can take significant amount of CPU time. Furthermore, if this process is done using programming languages which require repeated interpretation each time a loop is called like Matlab, Python or the like, extremely longer time is expected particularly for larger systems. In this new algorithm, the solution is done for all the nodes at once and not within loops. The solution methodology involves manipulating all the variables as column vectors. Then using shifting matrices, these vectors are sifted in such a way that subtracting relevant vectors produces the corresponding difference algorithm. It has been found that this technique significantly reduces the amount of CPU times compared with traditional technique implemented within the framework of Matlab.
Unlocking shale gas has been extremely successful during the last decade. Nevertheless, new challenges will continuously arise. One of the most pressing current issues is to know the stimulated reservoir volume (SRV), the part of the reservoir that actually received fracturing fluid. The most widely used technology for estimating SRV is downhole microseismic mapping. Under many conditions, it yields reasonably accurate/reliable information about SRV (Mayerhofer et al. 2008).
Unfortunately, it requires an observation well in close proximity to the treatment well in which to place the geophone string used to sense the small seismic signals. This requirement often makes it impossible to provide an SRV estimate for many of the hydraulic-fracture treatments that could benefit from this information.
This paper presents an alternative to the downhole-microseismic SRV mapping. A new method, stimulated reservoir characterization (SRC), is based on surface microdeformation measurements obtained with a precision surface tiltmeter array. Tiltmeter-based hydraulic-fracture diagnostics have been successfully used for more than two decades on more than 10,000 hydraulic-fracture treatments. SRV is typically calculated for highly jointed shale reservoirs or coal seams in which injected fluids can inflate a myriad of interconnected hydraulic fractures in two or more dominant orientations. The measured surface deformation is the superposition of all the deformation fields resulting from the inflation of each individual fracture. This makes the deformation-based approach for SRV estimation a convoluted process and requires much more complex tilt-data analysis than does a simple planar hydraulic fracture. This paper describes a new technique for tilt-based SRV estimation, which is capable of resolving spatial distribution, orientations, and volume percentages of the major components of a fracture network. Hence, the new technique allows not only an insight into the areal penetration of treatment fluids into the reservoir, but also an understanding of how multiple joint sets, each with unique orientations, are actually accepting the injected fluids and proppant. This paper includes synthetic data examples and SRV results derived by applying the new technique to a hydraulic-fracture-stimulation project in the lower Eagle Ford shale formation.
Reynolds, Murray Melvin (TAQA North) | Thomson, Susan (TAQA North Ltd.) | Quirk, David James (Trican Well Service Ltd.) | Dannish, Michael Bruce (TAQA NORTH) | Peyman, Faezeh (Penn West Energy Trust) | Hung, Allan (Trican Well Service Ltd.)
The Glauconitic formation is a Cretaceous age sandstone reservoir located across a large area of central Alberta, Canada. Discovered in the late 1970's, hydraulically fractured vertical wells could produce commercial volumes of natural gas from some of the higher permeability conventional sands. However, wide spread development of the majority of the tight gas sands was not economic with vertical wells.
With the introduction of multiple fractured horizontal well (MFHW) technology in recent years, and much better definition of the geology, a large unconventional resource play has developed in the Glauconitic, which could contain in excess of 5 tcf of gas in place plus associated natural gas liquids (Scotia Capital, 2009).
A pilot project was designed to test the completion effectiveness between a cased and cemented liner and an open hole packer system in this tight gas reservoir.
Two vertical microseismic observation wells were located in close proximity to two proposed horizontal wellbores, giving ideal conditions to test how the hydraulic fractures would grow and the ultimate fracture geometry, from two different completion methods.
In this paper we will present the microseismic results of the pilot project, as well as the early production history comparison between the two wells, and the hydraulic fracture effectiveness from a reservoir engineering aspect.
What's Ahead - YPs are the unconventional human resource required to decipher the energy future of the world.
The Schönkirchen Tief oil field is located in the Vienna basin in Austria. It is a pervasively fractured dolomite reservoir that has been produced for more than 50 years. The field is at the tail end of production, the wells are perforated close to the top of the reservoir, and water is injected downdip. Because of the location of the field close to one of the main gas pipelines in Austria, it is planned to convert the field into high-performance underground gas storage (UGS).
The field is characterized by a highly permeable fracture system and a less-permeable matrix system. It is expected that some incremental oil can be recovered because of gas/oil gravity drainage from the matrix.
In addition to gas/oil gravity drainage, diffusion will have an effect on the oil recovery. The injected gas is leaner than the equilibrium gas in the reservoir. Hence, gas components diffuse from the fracture system into the matrix and components of the oil diffuse toward the fracture system. This results in a modification of the properties of the oil affected by diffusion.
This type of gas injection results in a zone of decreased oil viscosity for gases such as CO2 and CH4 at the interface of the gas and the oil in the matrix. This zone of lower oil viscosity increases the gas/oil gravity-drainage rates.
The results show that the effect of diffusion can increase cumulative oil production up to 25% compared with a case neglecting the effect of diffusion. The effect of diffusion could be determined for various parameters such as permeability, porosity, fracture spacing, and matrix-block height. While for some of the parameters the effect of diffusion scales with the square root of time (e.g., permeability), for others an exponential relationship has been determined (fracture spacing).
The results derived for the example reservoir can be used more generally to screen whether the effect of diffusion should be incorporated into reservoir studies concerning nonequilibrium-gas injection and to determine how large the error could be in the case where diffusion is neglected.
Western Sichuan deep tight gas reservoirs are characterized by ultralow permeability, natural fractures, partial ultralow water saturation, and a hard brittle shale interlayer. The matrix permeability varies from 0.001 to 0.1 md. The natural-fracture width varies from several micrometers to 3.0 mm, but it could be up to 5.0 mm during well operations. Lost circulation--inducing severe reservoir damage and increasing nonproductive time--has frequently occurred during well drilling and cementation during the past 10 years. The traditional lost-circulation-control techniques such as physical, chemical, or physicochemical methods, which used to permanently choke the lost-circulation passage of the nonpay zone, are not suitable for the pay zone. Several technologies, including air underbalanced-drilling fluids, noninvasive drilling fluids, and traditional temporary-shielding-fluids (TSF) technology, were tried to prevent formation damage owing to lost circulation but none of them worked well. Air underbalanced drilling has to be given up because of formation-water influx and wellbore instability. Noninvasive drilling fluids are ineffective because of the low percentage of return permeability and low bearing strength of the mudcake in the fractured formation. Traditional TSF technology is applicable for the damage prevention only in reservoirs with fractures less than 100 um in width. Temporary-sealing-loss (TSL) fluids with millimeter-sized agents take advantage of acid-soluble bridging particles to rapidly form a tight plugging zone near the wellbore that efficiently seals the pore throats and fractures. TSL fluids were developed to prevent formation damage in leaky fractured reservoirs. With the application of the new TSL fluids, Well W2, in the second member of the Xujiahe formation, obtained a gas-production rate of 52.16×104 m3/d. Furthermore, lost circulation never occurred during drilling of Well W101.