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Abstract As part of HWYH Gas Plant development, hydraulic fracturing campaign commenced in 1998 to stimulate the sandstone and carbonate formations in the Ghawar gas fields in Saudi Arabia. To date, over 200 wells have been matrix acidized, acid fractured, and proppant fractured. Whereas post-treatment performance provides a good indication of treatment success, pressure transient analysis (PTA) remains the best approach to determine the effective fracture parameters such as fracture half-length and fracture conductivity. Knowledge of these two parameters is a key element to the optimization of hydraulic fracturing process. Introduction Ghawar gas is developed from two main reservoirs - the Khuff carbonates (calcite and dolomite) and the Pre-Khuff (Jauf and 'Unayzah) sandstones. Depending upon reservoir conditions, lithology, and production expectation, different fracturing procedures are adopted to develop these reservoirs. The incremental production from the reservoirs ascertains the success of the fracture treatments. For the Pre-Khuff sandstone reservoirs, because of the unconsolidated nature of some high potential sandstone layers, indirect fracturing technique has been adopted where the consolidated, low porosity section is perforated and from where the induced fracture is initiated.4 This procedure is implemented on our wells, has eliminated sand production but also introduced high near well skin. For soft formations, fracturing wells using fracpack technique and completing them with mechanical screen are being successfully implemented. For the Khuff carbonates, matrix acid or acid fracturing treatments are conducted to dissolve rocks, create wormholes, and propagate long, etched fracture to provide easy pathway for gas to move from the reservoir to the well. Successes on the Pre-Khuff sandstone treatments are usually judged by sand free production rate and conditions and by comparing post-fracture production increase with simulated, pre-fracture production based on reservoir properties calibrated by post-fracture production match. Success in Khuff carbonates are judged by the post-treatment incremental production compared to pre-treatment conditions. Success is also gauged by conducting different pressure transient tests to compute fracture length and conductivity. This article presents field cases from the carbonate and sandstone reservoirs treated with acid and proppant, respectively, and provides a general picture of how PTA has become an integral method to evaluate fracturing processes.
- Asia > Middle East > Saudi Arabia > Eastern Province > Arabian Basin > Widyan Basin > South Ghawar Field (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.97)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.97)
- (6 more...)
Abstract The common methods to model hydraulic fractures are based on the assumption of constant fracture conductivity. However, in some cases the hydraulic fracture conductivity may be a function of stress/pressure, and thus significantly change during production. It is reported that the hydraulic fracture conductivity may be reduced from a few to hundreds of folds in the literature. This paper presents a semi-analytical model to facilitate transient pressure analysis for hydraulically fractured wells with stress-dependent hydraulic fracture conductivities. This model is developed for both hydraulically fractured vertical wells and multi-stage fractured horizontal wells. Considering the stress-dependent hydraulic fracture conductivities leads to the mathematical model being strongly non-linear. In order to solve the problem, hydraulic fractures are discretized into several slab source segments. The fluid flow from formation directly to fractures and flow inside fractures are calculated at each time step. Pressure distribution can be computed with complete fluid flow distribution. Then, the conductivities of hydraulic fractures are updated based on the pressure distribution. In each time step, an iteration process is used to deal with the relationship between fracture conductivities and the pressure. The effect of stress-sensitive conductivities on transient pressure behavior is studied and type curves are documented. As the fracture conductivity decrease, the pressure and corresponding pressure derivative curves rise quickly and when the conductivity declines to the minimum value, the increasing pressure drop slows down. Therefore, a hump is formed on the pressure derivative curves. The slope of the hump is close to unit in log-log plot. The time of the hump's appearance and its size are determined by characteristics of hydraulic fractures, reservoir properties and production rate. Field examples from fractured vertical/horizontal wells are analyzed and reliable results are obtained.
- Asia (1.00)
- North America > United States > Texas (0.93)
- Geology > Geological Subdiscipline > Geomechanics (0.94)
- Geology > Rock Type (0.68)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
Abstract The presence of fractures and faults play a significant role in recovery and performance of tight reservoirs exploited with hydraulically fractured wells. Faulting may result in asymmetric reservoirs, i.e. different quality reservoirs across the fault plane, due to the displacement of reservoir blocks along the fault plane. Typically, numerical well-test packages are used to match the pressure responses of such complex geology and well geometry. The limitations of such approaches in terms of ease of use and wide range of possible solutions plead for more attractive approach. Hence, here a semi-analytical approach has been followed to develop a new practically efficient flow solution for a well intersecting a finite conductivity vertical fracture in an asymmetric reservoir. The solution is characterised mainly by the bilinear flow resulting from formation and fracture linear flows. The pressure derivative curve exhibits a distinctive feature of an early fracture linear flow regime at a very early time reflecting the first fluid flow into the well from the fracture only. The shape of the derivative plot also suggests the characteristics of a bilinear flow, quarter slope, uttering the fracture characteristics, followed by a radial flow, zero slope, articulating the quality of the two reservoirs. Type curves of dimensionless time and pressure are presented along with field cases for vertical wells intersecting natural fractures or exploited by hydraulically fractures. The results of this paper enable reservoir engineers to carry out modelling of such complex reservoir/well scenarios with increasing certainty and long-term benefits and greater additional and favourable business impacts. Introduction Ramey (1976) and Raghavan (1977) have previously presented a review of the work done on flow along and toward fractures. They highlighted that intersecting fractures will strongly affect transient flow behavior of the well. Houze et al. (1984) described a well intersecting an infinite conductivity fracture in a naturally fractured reservoir simulated using a double-porosity model. Cinco-Ley and Samaniego (1978) presented a semi-analytical solution for the analysis of the transient pressure data of analysis for fractured wells in symmetric reservoirs, which is most likely to occur in the case of small fractures or strike-slip faults. Yet, in the case of reverse or normal faulting with large throw (Juxtaposing), different quality reservoirs could adjoin the fault plan. That is, faulting may result in a sudden displacement of rock along the fault plane that possibly yields, a large-scale slippage resulting in different quality fault blocks on both sides of the fault. Many production logs have shown two different fault-blocks resulting from a reverse fault that offset two zones sequence. Figure 1 illustrates a good example of faulting that juxtaposes different geology across the fault plane, whereby; two different quality zones are aligned through the fault plane. Here a semi-analytical solution for such a scenario is presented.
- North America > United States > California (0.28)
- North America > United States > Texas (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff C Formation (0.99)
- (4 more...)
Abstract Fractures often influence production behaviour in hydrocarbon reservoirs, yet the pressure transients observed in the wells may not show the conventional well-test signatures. In this case, the effect of fractures on production would be misinterperted or even completely missed. Fracture networks are commonly multi-scale and properties including aperture (or conductivity), length, connectivity and distribution vary greatly within a reservoir. The heterogeneous nature of fractured reservoirs make them very difficult to characterise and develop. In addition, the location of a producer within the fracture network also control flow rates and affect the pressure response; however, conventional well-test analysis assumes that the producer is located in symmetrical fracture networks. To improve our understanding of fracture flow behaviour from well-test data, and in order to better characterise the impact of fractures on reservoir performance, we investigate the effect of variations in fracture conductivity and location of the producer in the fracture network on the pressure transient responses. Naturally fractured reservoirs (NFR) with well-connected fracture networks are traditionally simulated using the Dual-Porosity (DP) model. However, several studies have shown that the classic DP response (V-shape) corresponding to the DP model is an exceptional behaviour applicable only to certain reservoir geology and does not apply to all NFR. To overcome the limitations of the characteristic flow behaviour inherent to this model, we employ Discrete Fracture Matrix (DFM) modelling technique and an unstructured-grid reservoir simulator to generate synthetic pressure transients in all fracture networks that we analysed. Our rigorous and systematic geoengineering workflow enables us to correlate the pressure transients to the known geological features of the simulated reservoir model. We observed that depending on the location of the producer in the fracture network and the properties of the fractures that the producer intercepts, the synthetic pressure transients vary significantly. We therefore use these insights to quantify the impact of variation in fracture conductivity and producer location on fracture flow behaviour and systematically present interpretations to these behaviours. Our findings enable us to interpret some unconventional features of intersecting fractures with variable conductivity. We observed that the behaviour of two intersecting fractures where the well asymmetrically intercepts a finite-conductivity fracture can be similar to that of a well intercepting a fracture in a connected fracture network with uniform fracture conductivity. Furthermore, a well intercepting a finite-conductivity fracture in NFR with both finite- and infinite-conductivity fractures would yield a dual-porosity response that may otherwise be absent if the fracture network is assumed to have uniform conductivity.
- Geology > Geological Subdiscipline > Geomechanics (0.47)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- Europe > United Kingdom > England > Hampshire Basin > PL 089 > Block 98/6 > Wytch Farm Field > Sherwood Formation (0.99)
- Europe > United Kingdom > England > Hampshire Basin > PL 089 > Block 98/11 > Wytch Farm Field > Sherwood Formation (0.99)
- Europe > United Kingdom > England > Hampshire Basin > PL 089 > Block 97/15 > Wytch Farm Field > Sherwood Formation (0.99)
- (5 more...)
Many wells, particularly gas wells in low-permeability formations require hydraulic fracturing to be commercially viable. Interpretation of pressure-transient data in hydraulically fractured wells is important for evaluating the success of fracture treatments and predicting thefuture performance of fractured wells. This page includes graphical techniques for analyzing post-fracturepressure transient tests after identifying several flow patterns that are characteristic of hydraulically fractured wells. Often, identification of specific flow patterns can aid in well test analysis. Five distinct flow patterns (Figure 1) occur in the fracture and formation around a hydraulically fractured well.[1]
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)