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As part of the evaluation of a deep sandstone interval in eastern Venezuela, hydraulic fracture employing high strength proppant was used to determine the formation's flow potential. The interval fractured is at a depth of more than 16,000 feet and has a bottom hole static temperature of 288deg.F, conditions which require a good knowledge of reservoir and fluid properties. The design of this operation incorporated properties. The design of this operation incorporated a number of data gathering steps to ensure that fracture geometry, in-situ stresses, and fracturing fluid behaviour were understood prior to executing the treatment.
Mechanical properties logs indicated that two separate fractures would develop at different pressures, the upper fracture initiating some 600 psi pressures, the upper fracture initiating some 600 psi above the initiation pressure of the lower interval. The first pump-in test performed on the well consisted of a ball-out employing 600 balls transported in a linear gel frac fluid. Following this a temperature log was run across both intervals. The deflections indicated that two fractures had indeed been generated, both fractures coinciding well with the height predicted by the sonic log, although the upper fracture had grown some 50 feet higher than the prediction.
High temperature crosslinked water based gel was pumped as a minifrac without diverter (no ball pumped as a minifrac without diverter (no ball sealers) at a rate of 18 bpm as the second downhole pumping test. This part of the operation was pumping test. This part of the operation was designed to determine actual fracture geometry, fracture gradient, and particularly the leakoff coefficient of this fluid.
The data on fracture height, fracture gradient, post-fracture pressure decline and fluid loss obtained post-fracture pressure decline and fluid loss obtained from the logs and pump-in tests were incorporated into the design of the main fracture and the operation was successfully completed. The paper describes each of the pumping tests and shows how the test results and log derived data were used to verify the eventual design of the propped fracture.
The success of a hydraulic fracture is strongly dependent on an understanding of orientation and overall geometry of the created fracture, which in turn are primarily functions of the orientation, magnitude and distribution of in situ stresses in the reservoir an adjacent strata.
To achieve credible engineering estimates of fracture geometry, fluid efficiency, and potential risks of premature screen-out, the engineer must reliably history match the observed net-fracturing pressure. Measurement of net-fracturing pressure requires first, and foremost, a reliable estimate of the formation closure stress, to which the net pressure is referred.
This paper documents both the theory and several example field applications of a novel flow-pulse closure stress determination method. The flow-pulse technique requires only small changes in fracture treatment pumping schedule that can be accomplished at little to no extra cost, yet it allows a robust estimation of formation closure stress in real time. The flow-pulse technique involves pumping a small minifrac (usually with water) and then pumping small pulses (of about 5 bbl) of fluid during the pressure decline. There is a dramatic change in pressure response when flow pulses are pumped into an open fracture vs. a fracture that is already closed.
After a brief, but disappointing, romance with purely theoretical fracture models, the industry has now acknowledged the central role of actual measured treatment data in any serious fracture analysis effort. A large segment of the industry, however, continues to use either vastly over-simplified models (mostly 2D) or denies the value of fracture analysis altogether by simply using empirically derived fracture treatment designs and procedures. A common, however mistaken, justification for the latter two approaches is that it is simply not feasible to gather the necessary data for serious (3D, real-data) fracture analysis. This paper attempts partially to address this concern with feasible data collection for real-data fracture analysis.
Real-data fracturing analysis requires the determination of the actual observed net-fracturing pressure during a fracturing treatment and then running a suitably flexible physical model of the fracturing process until the model-predicted net-fracturing pressure matches the observed net-fracturing pressure.
The pressure decline analysis of minifrac treatments in uniform formations, using the type curves presented by Nolte, yields information on leak-off which is necessary for fracture treatment design. A similar analysis for minifracs initiated near or at the interface of two formations of different leak-off characteristics and penetrating both formations is presented in this paper. It is concluded that the type curves given by Nolte can be used for this case with appropriate definitions of an effective (or average) leak-off coefficient and an equivalent fracture radius. The effective leak-off coefficient is the weighted average of the individual leak-off coefficients of each formation, relative to the minifrac areas in the two formations. Similarly the equivalent fracture radius is the radius of a circle of an area equal to the sum of the areas of the minifrac in the two formations. An estimate of the individual leak-off coefficients of each formation may be obtained by a trial and error comparison of simulated values of the P- pressure (as defined by Nolte), using a three dimensional fracturing simulator, with the one obtained directly by minifrac pressure decline type curve analysis. Four examples of application of the new theory to North Sea oil wells are presented.
The pressure decline analysis of minifrac treatments was first described by Nolte who applied it for minifrac treatments confined in one formation. Smith, Miller, and Haga have applied Nolte's method for unconfined minifrac treatments contained in one formation and being essentially penny shaped. The success of the method depends on the ability to derive a closed form solution based on the assumption that the fracture area is proportional to pumping time for high efficiency (storage dominated) minifracs, and proportional to the square root of pumping time for low efficiency (leak-off dominated) ones. These two cases provide the bounds for actual minifrac pressure behavior.
A similar type of analysis is described in this paper, where the fracture during the minifrac treatment is assumed to have propagated into two zones of different leak-off coefficients. Fracturing treatments initiated near or at the interface of two formations have been applied in the oil fields of the North Sea to obtain relatively stable well completions. The minifrac and main fracture treatments propagate in two formations of different leak-off characteristics and mechanical properties. The usual minifrac pressure decline analyses yield leak-off coefficients that vary significantly from well to well, although the wells are located in the same region of the field and the minifracs are performed from perforations at the interface of the same formations. The calculated leak-off coefficients are often different from the leak-off coefficients obtained from minifracs contained entirely in either of the two formations. In many instances the analysis results from minifracs near formation interfaces are completely discarded as "unbelievable" and leak-off coefficients from general field experience are used to design the fracturing treatments. These discrepancies in minifrac interpretations are attributed to the complex fracture geometry and the different leak-off characteristics of the two formations. The need of a more detailed leak-off theory is apparent for such complex cases.
When hydraulic fracturing operations are conducted in thick reservoir sections, it is common for the perforated interval to be long but yet still significantly shorter than the distance between reliable barriers to fracture propagation. Under these circumstances the fracture shape will change continuously as it evolves from the perforated interval, thus complicating the interpretation of pressure decline data measured during pressure decline data measured during prestimulation mini-frac tests. prestimulation mini-frac tests. This paper presents a pressure decline analysis which assumes the fracture to have evolved as a family of confocal ellipses, which thereby ensures a smooth transition between the simpler fixed geometries which correspond to the injection of either very small or very large volumes of fluid (KCD and penny, respectively). The analysis enables the fracture shape and dimensions to be estimated, together with the fracture fluid-loss coefficient. An example is given of the application of this method, and a comparison is made with values determined assuming simpler, fixed shape models. The influence of injected fluid volume is considered. A rapid method for determining the Nolte "match pressure", P*, is also described.
A dominant factor in the propagation of hydraulic fractures is the loss of fracturing fluid to the formation. Whilst it is possible to perform laboratory measurements of fluid loss under simulated field condition in practice local geological variability and the possible presence of natural fractures mean that significant departures from laboratory values may frequently occur. Consequently in-situ methods for determining the fluid loss coefficient from observations of the pressure decline following a small calibration pressure decline following a small calibration fracturing operation have been developed and applied.
To date, pressure decline analyses are available for three simple fracture models, namely the Perkins - Kern, Nordgren, (PKN), the Khristianovic -Geertsma-de Klerk , Daneshy (KGD) and the Penny shaped fracture. In many instances it is probably adequate to idealise the fracture geometry as falling into one of these three categories. However, sometimes it is desired to perform an hydraulic fracturing operation in a thick perform an hydraulic fracturing operation in a thick reservoir section, but where there is little obvious potential for fracture confinement. Under these potential for fracture confinement. Under these conditions there is likely to be significant height growth even if the perforated interval is long and, depending on the volume of fluid injected, it may be inappropriate to assume one of the above simple geometries when interpreting mini-frac pressure decline data.
On the basis of laboratory studies, Daneshy concluded that in the absence of confinement, fractures growing from a long perforated interval may be considered to evolve as a family of confocal ellipses, with the top and bottom of the perforated interval acting as foci. This concept is perforated interval acting as foci. This concept is employed below in conjunction with the principles developed by Nolte to provide a pressure decline analysis appropriate to a continuously evolving fracture geometry. A smooth transition between KGD and Penny type analyses is therefore obtained, depending on the volume of fluid injected. The analysis enables the fracture shape and dimensions to be estimated, as well as the fluid logs coefficient.
Abstract Characterization of hydraulic fracture system in multi-fractured horizontal wells (MFHW) is one of the key steps in well spacing optimization of tight and shale reservoirs. Different methods have been proposed in the industry including core-through, micro-seismic, off-set pressure data monitoring during hydraulic fracturing, pressure depletion mapping, rate-transient analysis, pressure-transient analysis, and pressure interference test. Pressure interference test for a production and monitoring well pair includes flowing the production well at a stable rate while keeping the monitoring well shut-in and recording its pressure. In this study, the coupled flow of gas in hydraulic fractures and matrix systems during pressure interference test is modeled using an analytical method. The model is based on Laplace transform combined with pseudo-pressure and pseudo-time. The model is validated against numerical simulation to make sure the inter-well communication test is reasonably represented. Two key parameters were introduced and calculated with time using the analytical model including pressure drawdown ratio and pressure decline ratio. The model is applied to two field cases from Montney formation. In this case, two wells in the gas condensate region of Montney were selected for a pressure interference test. The monitoring well was equipped with downhole gauges. As the producing well was opened for production, the bottom-hole pressure of the monitoring well started declining at much lower rate than the production well. The pressure decline rate in the monitoring well eventually approached that of the producing well after days of production. This whole process was modeled using the analytical model of this study by adjusting the conductivity of the communicating fractures between the well pairs. This study provides a practical analytical tool for quantitative analysis of the interference test in MFHWs. This model can be integrated with other tools for improved characterization of hydraulic fracture systems in tight and shale reservoirs.