Fractures can be first-order controls on fluid flow in hydrocarbon reservoirs. Understanding the characteristics of fractures such as their aperture, density, distribution, conductivity, connectivity, etc, is key for reservoir engineering and production analysis.
Well testing plays a key role in the the characterisation of fractured reservoirs, especially. New advances in the Pressure Transient Analysis (PTA) have enabled the interpretation of production data in a way where the resulting geological scenarios are in better agreement with fracture patterns observed in outcrop analogues.
Traditionally, Drill Stem Test (DST) data have been the primay source of information for well testing. However, we hypothesise that wireline conveyed tools designed for Interval Pressure Transient Testing (IPTT) could yield a more throrough description of the near-wellbore heterogeneities, including fractures.
Hence, we investigate the applicability of IPTT for characterising fractured reservoirs using detailed numerical simulations models with accurate wellbore representation to generate synthetic IPTT responses that can obtained through a next-generation wireline testing tool called SATURN. We particularly focus on cases where fractures are present in the near-wellbore region but do not intersect the wellbore. The study included parameters such as fracture densities and conductivities, distance between fractures and wellbore and the vertical extension of the fractures across geological beds.
The impact of the different fracture scenarios on the pressure transient tests was recorded as characteristic signatures on diagnostic plots (pressure derivative curves). We have called these curves "IPTT-Geotypes"; they can be used to assist the interpretation process of IPTT responses. To the best of our knowledge, this is the first time pressure derivative type curves for IPTT in fractured reservoirs are presented in the literature.
A field example of an IPTT case was analysed using the concept of geological well testing. We integrated the information from petrophysical logs and the IPTT-Geotypes to assist the calibration of a reservoir model developed to represent the geological setting of the tested reservoir interval. The results provided a sound interpretation of the reservoir geology and quantitative estimation of the matrix and fracture parameters.
One of the main uncertainties when designing polymer floods is the polymer injectivity, an important parameter that can affect the economics of the process. Reservoir simulation can be used to forecast injectivity, but the process is not straightforward and can be affected by grid size and other factors. Analytical methods are also available for that purpose, but they are considered too simplistic to deal with realistic reservoir conditions. The aim of this paper is to show that this is not the case and that simple analytical tools can be accurate and of great help to predict or history match polymer injectivity.
The analytical method has been developed by Lake in his classical textbook on Enhanced Oil Recovery, but few applications are documented in the literature. This paper will review the method and corresponding equations before presenting several actual field cases of injectivity in polymer flood pilots or tests from several countries that have been matched analytically.
Although it has not been used very often, the method has been found to give very good results in most of the field cases tested in a variety of situations; these cases will be presented along with recommendations on how to apply the method and a discussion of the results. Sensitivities to the various parameters will also be presented. Once the equations are programmed in a spreadsheet, the matching process takes only a few minutes and it is easy to run various scenarios and sensitivities.
Polymer injectivity remains one of the less understood and less predictable aspects of polymer flood projects. This paper will encourage engineers who are planning such projects to use simple yet accurate analytical tools before embarking in more complex and time-consuming reservoir simulations.
Acid fracture operations in carbonate formations are used to create highly conductive channels from the reservoir to the wellbore. Conductivity in calcite formations is expected to be highest near the wellbore, where most of the etching occurs. The near wellbore fracture etched-width profile can be estimated from the measured temperature distribution. Temperature data can be obtained from fiber optic distributed temperature sensing (DTS) installed behind casings to monitor fracturing operations.
Heat transfer is commonly coupled in acid fracture models to account for temperature's effects on acid reactivity with carbonate minerals. Temperature profiles are usually evaluated during simulations of fracture fluid injection, but seldom during fracture closure. Since most of the acid is spent during injection, many models have assumed that the remaining acid reacts proportionally along the fracture length. Because of this assumption, neither acid spending nor temperature is usually simulated during fracture closure.
In this study, a fully integrated temperature model was developed wherein both the acid reaction and heat transfer were simulated while the fracture was closing. At each time step, transient heat convection, conduction, and generation were calculated along the wellbore, reservoir, and fracture dimensions. Modeling temperature during this transient period provides a significant understanding of the fracture etched-width distribution. During shut-in, cold fracture fluids are heated, mainly because of heat flow from the formation to the fracture. The amount of fluid stored in the fracture determines how fast the fluid is heated. Wider fracture segments contain larger amounts of cold fracture fluids, resulting in it taking longer to reach the reservoir temperature. Because of this phenomenon, near a wellbore, the vertical fracture etched-width profile can be determined from the temperature distribution. Also, minerals' spatial distributions along the wellbore's lateral can be estimated in multistage acid fracturing. This is done by minimizing the difference between the observed and modeled temperatures.
This evaluation of etched width profiles at the fracture entrance provides an estimation of fracture-conductive channel locations. Moreover, it has significantly improved the understanding of mineralogy distribution in multi-layer formations. This information will be particularly useful when designing acid fracturing jobs in nearby wells or revisiting the same wellbore for further stimulation.
The technical and economic successes of deep geothermal development rely on reducing drilling and completion risks. In the closely related oil and gas activities, the risk taken by the investors is balanced by the high reward that successful projects achieve by immensely offsetting the losses of the failed wellbores. Geothermal projects experience similar risks, however, the potential reward is limited by the competition with other energy sources, in a heavily regulated market. The economic acceptability of geothermal power generation requires low risk drilling and completion technologies that would work under many different geological conditions.
When wells are drilled into a petro-thermal formation, sometimes referred to as hot dry rock (HDR), there is normally no clear circulation path between these wells and when this path exists, the transmissivity is so low that no economical project is possible. Enhanced geothermal systems (EGS), in these circumstances is closer to reservoir creation than to conventional reservoir stimulation. Therefore, developing technologies that achieve the designed EGS size and transmissivity is vital to deep geothermal development.
The EGS becomes a viable proposition, when enough rock surface can be contacted by the geothermal fluid, and when the flow path runs smoothly through a sufficient rock volume to minimize the energy depletion and have the project running over a long period, compatible with a positive net present value (NPV). To that end, the well design and its completion system have to be engineered to maximize the chances of properly creating the EGS. In this paper, lessons learnt from past geothermal experience are reviewed and analysed to propose a multi-stage system as a mean of improving geothermal wells completion reliability. Current oil and gas (namely "unconventional") completion technologies related to multi-stage stimulation have been reviewed and different options are discussed in the scope of a deep geothermal hot dry rock project. While previous works conclude that technologies developed for oil and gas are readily available and applicable to deep geothermal projects and EGS (Gradl, 2018), this study shows that shortcomings exist and that further developments are necessary to reliably and economically complete EGS projects. The necessary tests before running different parts is also discussed. Other options for reservoir creation are debated with their potential benefits and associated risks. The developments that could make them work in an EGS project are discussed.
Using planar fracture models to match treatment pressure and improve understanding of the fracture geometry generation is not a new concept. Knowledge gained from this exercise has historically been used to improve engineered fracture completions and production, and maximize net present value (NPV); however, at some point during the progression from vertical to horizontal wellbores, many within the industry have forgotten about the learnings that can still be gained from current fracture models. Engineered completions have been largely replaced by spreadsheet efficiencies relevant to operations rather than production in too many cases. Some images of unconventional well stimulation treatments portray fractures growing in every direction, forming patterns that resemble shattered windshields, and have often excluded the known physics related to rock geomechanics, reservoir properties, and geology. Excuses to dismiss modeling are numerous and are gaining the reasoning of conformists.
Unconventional resource plays might or might not contain large numbers of natural fractures; but, current fracture models can still be used to gain insight into the fracture geometries being generated. While the development of complex fracture models continues to evolve, the industry can still gain insight to fracture geometry and resulting production using current planar fracture modeling. Caveats to this process are that it requires: Valid measured data to establish model constraints. The engineer to understand the basic physics of how fractures are generated and when (and when not) to twist the "knobs" in the model. The engineer to understand which "knobs" should be used based on real diagnostics information. The actual single well production to be an integral part of the process.
Valid measured data to establish model constraints.
The engineer to understand the basic physics of how fractures are generated and when (and when not) to twist the "knobs" in the model.
The engineer to understand which "knobs" should be used based on real diagnostics information.
The actual single well production to be an integral part of the process.
This paper demonstrates the results of honoring data measurements from a multitude of potential sources, including downhole microseismic data, downhole deformation tiltmeters, offset pressure monitoring, DTS, DAS, diagnostic fracture injection test (DFIT) analysis, injection as well as production data with bottomhole pressure measurements, etc., and the resulting observations and conclusions. Several industry examples are discussed to help frame the vast amount of information possible to help engineers do a better job of including more diagnostics into routine operations to provide additional insight and ultimately result in improved models and completion designs.
This paper is not intended to merely demonstrate the results of the work but to spark an interest in bringing more intense engineering back to fracture stimulation modeling for horizontal completions.
Understanding pressure and pressure relationships is the key to safe well control. Yet, to date, the primary focus of well control has centred on recovery rather than prevention. Incidents related to loss of well control largely occur when the primary barrier, hydrostatic pressure from the drilling fluid, fails to prevent an influx; thus requiring the secondary barrier, closing of the BOPs, to engage in order stop the breach from becoming a full-blown, well control incident. Influxes occur, most often, during the tripping operation where the swab effect lowers the bottomhole pressure below the formation's pressure and can be commonly misidentified when "wellbore breathing," nuisances gases, or cement setting are involved. Influxes can also occur when drilling into unexpected, higher-pressure zones.
The effects of adding iron oxide NPs on the rheological and filtration properties of aqueous bentonite suspensions have been studied by several researchers. This paper presents an investigation into the effect of catalytic nanoparticles on the efficiency of recovery from continuous steam injection. A number of ongoing industry research projects are developing nanoparticles that work at the reservoir level and for fluid treatment. Though they may be a few years away from finalization, these efforts highlight nanotechnology’s increasingly sophisticated and growing application scope. This work focuses on the laboratory techniques for developing, assessing, and analyzing innovative water-based drilling fluids containing iron oxide (Fe2O3) and silica (SiO2) nanoparticles.
Improvements in MEMS sensor technology are creating rapid momentum toward the use of tiny, rugged, and inexpensive sensors to replace larger, costlier, and more fragile legacy-technology sensors in directional drilling. A new holistic approach to optimizing wellbore economics is bridging the gap between planning and execution and bringing well construction into the digital era to improve data use, enhance collaboration, boost efficiency, and increase safety.
A single-well polymer-injection and back-production test has been performed in an oil and gas field offshore Norway. The objective of the test was to verify at field conditions the properties measured in the laboratory for the biopolymer schizophyllan. Continued enthusiasm in the well-testing segment of the oil industry is apparent. Even though there was a smaller number of presentations among various conferences related to well testing in 2016, there are articles that contribute significantly for the experts and the upcoming generation. The application of high-precision downhole temperature sensors has resulted in pressure-transient analysis (PTA) being complemented or replaced by temperature-transient analysis (TTA).
Predicting the properties of reservoirs beyond the wellbore has been the cornerstone of reservoir characterization. The outcome provides the framework for efficient management and optimization of hydrocarbon reservoirs. Proper reservoir characterization affects all reservoir types and all stages during the life of a field. Far-field characterization encompasses seismic, electromagnetic, and other geophysical surveys. This characterization can be facilitated in various configurations such as cross-well or surface-to-wellbore, accomplished while drilling, in open and cased wells, and while producing hydrocarbons.