Existence Of Natural Fractures Research Articles

Study on the interaction between hydraulic fracture and natural fracture under high stress

The existence of natural fractures in the reservoir has a great influence on the formation of complex fracture network, but the interaction between hydraulic fractures and natural fractures under high stress was rarely studied. Through laboratory tests, the law and characteristics of the interaction between hydraulic fractures and natural fractures under high stress were studied from the aspects of natural fractures angle, size, quantity, production method and ground stress in this study. Based on these interaction characteristics, a complex fracture network formation method of deep reservoir was proposed, which provided reference for engineering practice. The criterion of interaction between hydraulic fracture and natural fracture was improved, and the calculation method of rock tensile strength in three-dimensional state was proposed, which was applied to the criterion of fracture opening and fracture expansion. Combined with laboratory tests, a special interaction mode of hydraulic fracture passing through a certain position from the direction to end A (F-Type crossing mode) under high stress was proposed, and the criterion of this interaction mode were obtained. The three-dimensional finite discrete element model (FDEM) was used to investigate the effects of natural fracture strength and fracturing fluid viscosity on hydraulic fracture propagation under high stress. The results showed that the natural crack strength has great influence on the width, volume and shape of hydraulic crack. Small difference of fracturing fluid viscosity has little influence on fracture propagation, but high viscosity fracturing fluid has a greater influence on fracture propagation. This study provided reference for hydraulic fracturing engineering.

Efficient production optimization for naturally fractured reservoir using EDFM

Naturally fractured reservoirs make important contributions to global oil and gas reserves and production. The modeling and simulation of naturally fractured reservoirs are different from conventional reservoirs as the existence of natural fractures. To address the development optimization problem of naturally fractured reservoirs, we propose an optimization workflow by coupling the optimization methods with the embedded discrete fracture model (EDFM). Firstly, the effective and superior performance of the workflow is verified based on the conceptual model. The stochastic simplex approximate gradient (StoSAG) algorithm, the ensemble optimization (EnOpt) algorithm, and the particle swarm optimization (PSO) algorithm are implemented for the production optimization of naturally fractured reservoirs based on the improved versions of the Egg model and the PUNQ-S3 model. The results of the two cases demonstrate the effectiveness of this optimization workflow by finding the optimal well controls which yield the maximum net present value (NPV). Compared to the initial well control guess, the final NPV obtained from the production optimization of fractured reservoirs based on all three optimization algorithms is significantly enhanced. Compared with the optimization results of the PSO algorithm, StoSAG and EnOpt have significant advantages in terms of final NPV and computational efficiency. The results also show that fractures have a significant impact on reservoir production. The economic efficiency of fractured reservoir development can be significantly improved by the optimization workflow.

Experimental investigation of flow diversion and dynamic retention during polymer flooding in high salinity fractured carbonates using CT imaging

The successful record of polymer flooding in improving oil production from sandstone reservoirs has encouraged the expansion of its application in carbonate reservoirs. However, the existence of natural fractures, high permeability contrast, and harsh conditions of carbonate reservoirs provide significant challenges for achieving an optimized performance of polymer flooding. It is crucial to establish an appropriate polymer that can offer an optimum flow behavior for in-depth mobility control under reservoir conditions. This study presents in-situ saturation monitoring to evaluate the mobility control effect and identify the flow diversion during polymer injection in high salinity fractured and unfractured carbonate rocks. A synthetic polymer, acrylamido tertio-butyl sulfonate (ATBS) was used and prepared in 200,000 ppm brine salinity. The flow behavior of polymer solution was investigated in bulk rheology tests followed by single-phase core flooding experiments. The flooding apparatus was coupled with a CT scanner to produce 3D images for determining the fluid saturation distribution and inaccessible pore volume (IPV) in real time. Accordingly, flow diversion across fracture-matrix system during polymer injection and the dynamic retention after brine post-flush were identified. The flow experiments showed a shear thickening behavior for the injected polymer solution in the fractured core and no degradation was noticed under in-situ conditions. Based on the fluid saturation profiles, the established flow resistance in the fracture region was prominent to induce flow diversion from the fracture into the matrix. Compared to the case in unfractured rock, the IPV in the fractured rock was approximately 2.5 times higher which was at 53% after 1 PV injection. An additional 23% of IPV was subsequently penetrated upon a continuous polymer injection for 5 PV. In post-flush stage, the fractured core retained about 87% of the injected polymer solution at 1 PV which was then minimized to 7% after 10 PV injection. The entrapped polymer in the fractured core was potentially induced by hydrodynamic retention. This work ascertained the potential of polymer flooding to effectively sweep the fractured carbonates at high salinity environment under certain circumstances for a better conformance.

Experimental study on hydraulic fracture propagation behavior on dolomite rocks with open-hole completion

To determine to discuss fracture mechanisms and the possible encounter problems in open-hole fracturing in tight carbonation, tri-axial hydraulic fracturing experiments were performed on dolomites with acoustic emission monitoring. The results demonstrate that a complex fracture network is difficult to create in most cases even if the dolomite has high brittleness. In general, fractures likely have three types of fracture geometry, namely, bi-wing fractures, local multiple fractures and complex multiple fractures. However, even if multiple fractures can be initiated with open-hole completion, they still can finally merge into one dominant hydraulic fracture (HF). Branch fractures can be observed with low horizontal stress difference and low fluid viscosity. The breakdown pressure on dolomites has a positive relationship with the high fluid viscosity and fluid injection rate, but a negative relationship with the high horizontal principal stress difference. The existence of natural fractures and critical engineering parameter differences should simultaneously contribute to the ratio of branch fracture and diverge fracture. The microscopic observation results reveal that natural fractures that are infilled with mixed calcite minerals are more likely activated due to the lower strength of these minerals, and the main HF is arrested with a natural fracture that is infilled with high-strength calcite minerals. The separation of calcite clusters may exert competing effects on the fracture conductivity. On one hand, the debonded calcite clusters can seal and plug open HFs and reduce the fracture conductivity if the fracture width is not substantial. On the other hand, a calcite cluster can be a type of natural self-proppant to sustain long-term conductivity. The selection of open-hole completion in dolomite selection increases the risks of wellbore deformation but no serious wellbore collapse can be observed. Thus, hydraulic fracturing using open-hole completion can be recommended in dolomite reservoir development if the fracture height containment problem is not a critical issue.

Fracturing Optimization Design of Fractured Volcanic Rock in Songliao Basin Based on Numerical Research and Orthogonal Test

Abstract The efficient development of fractured volcanic reservoir relies on fracturing, while the existence of natural fractures has an important impact on hydraulic fracturing in this reservoir. There are few reports on fracturing optimization of deep volcanic gas reservoirs in Songliao Basin in China; thus, the parameter optimization under single-stage action is studied. On the basis of logging interpretation, coring observation, and seismic interpretation, the fracture development degree is obtained. By employing numerical simulation and orthogonal tests, hydraulic fracturing optimization design is carried out. The results indicate that the pumping rate of 0.01 m3/s/m and perforation direction parallel to the maximum principal stress are the optimum parameters for the studied volcanic reservoirs. In addition, multibranch seam expansion will occur when the displacement reaches 0.01 m3/s/m according to fracture morphology results after fracturing. And the research method has certain significance for improving the fracturing design of fractured reservoir in the research block.

Organic-rich shale caprock properties of potential CO2 storage sites in the northern North Sea, offshore Norway

Assessment of the geomechanical properties of organic-rich shale caprocks is critical for a successful CO2 storage into a saline aquifer. In this study, we investigated the geochemical properties of the organic-rich shale caprocks of the Draupne and Heather formations, overlying the potential sandstone reservoirs of Sognefjord, Fensfjord, and Krossfjord formations in the northern North Sea, offshore Norway. The caprock's depositional variations within the sub-basins are established by analyzing the gamma-ray shape and stacking patterns. The effect due to differences in depositional environments, on the caprock compaction behavior is investigated by integrating petrographical analysis of core and cutting samples from 3 wells and by rock physical analysis of wireline log data from 27 exploration wells. Three rock physics templates are used where the wireline log data are interpreted using the published background trends. The effect of kerogen type, maturation level, and deposition environment on caprock properties within the study area are also evaluated. Moreover, the caprock property, such as brittleness, is estimated by using four mineralogy and elastic property-based, empirical relations, which is a quantitative measure of caprock property with respect to changes in stress-state. Finally, the seismic inversion method is assessed for the possibility of extracting caprock properties from surface seismic data. Regardless of compaction processes, the results indicate that the Heather Formation is mechanically stronger than the Draupne Formation. However, both formations appear to be ductile in nature. The depositional environments control the mineralogical composition and fabric of the Draupne and Heather formations, which influence the caprock properties significantly. Results also show that the effect of TOC on caprock properties is insignificant in the study area. The brittleness of the organic-rich shale caprocks in the study area follows a different trend compared to the published trends. We also observed an excellent correlation between the log-derived elastic properties and geomechanical parameters. Still, it is difficult to assess the caprock elastic properties from seismic due to the overlap of data clusters. The evaluation of caprock geomechanical behaviors is challenging as these properties are site-specific and also influenced by other factors such as exhumation, in-situ stress conditions, the existence of natural fractures, and their orientations.

Numerical simulation of fractured vertical well in low-permeable oil reservoir with proppant distribution in hydraulic fracture

In this paper, numerical simulations of fractured vertical well in low-permeable oil reservoir are carried out and two issues: threshold pressure gradient (TPG) in reservoir matrix and proppant distribution in hydraulic fractures are focused on. A physical definition of effective fracture length (EFL) is presented to evaluate the fracture effectiveness due to uneven proppant distribution. In terms of numerical processing for TPG, based on the subsurface Darcy's flow module in COMSOL Multiphysics, an effective numerical simulation method is adopted by substituting the gravitational acceleration vector in Darcy's law (Liu et al., 2019b). The simulation results show that, proppant distribution has great influence on fracture effectiveness. Unappealing proppant distribution can reduce effective fracture length by 49.6%, which is negative for low-permeable oil reservoir development. TPG in reservoir matrix mainly affects the moving boundary and pressure-disturbed area in reservoir. When TPG in matrix reduces from 0.02 MPa/m to 0 MPa/m, the distance of moving boundary at 300 days could increase for almost double and pressure-disturbed area enlarged drastically for around 74%. Furthermore, a heterogenous low-permeable oil with secondary fracture networks is designed to study the joint effect of TPG and proppant distribution. If we neglect these two factors, cumulative oil rate will be greatly overestimated by 38.6% at 1000 days. At the same time, the existence of natural fractures could also affect the streamline distribution in low-permeable oil reservoir and contribute to fluid flow in reservoir.

Performance of enhanced geothermal system (EGS) in fractured geothermal reservoirs with CO2 as working fluid

Creating an open, connected fracture by hydraulic stimulation is vital to heat mining in an enhanced geothermal system (EGS). The existence of natural fractures, which seriously affects the development pattern, can complicate the hydraulic fractures. Different fracture propagation patterns of hydraulic fracturing can be achieved through different fracturing processes under certain natural fracture scales. Besides, CO2 has attracted a lot of attention as working fluid because of its superior hydrothermal properties and CO2 geological storage. At present, the study of EGS for fractured geothermal reservoirs with CO2 as working fluid is quite limited. In this paper, we firstly presented a three-dimensional (3D) thermal–hydraulic-mechanical (THM) coupled model to analyze performance of EGS in fractured geothermal reservoirs with different natural fractures scales, reservoir stimulation scales, and working fluids (water and CO2), aimed to guide reservoir stimulation and fracture parameter design. The results are showed as follows: If not forming connected fractures, the existence of natural fractures would cause fluid loss, an increase in natural fracture density by 0.4%, and the heat extraction rate decreases 0.06 MW on average; Forming connected fractures in the foundation of natural fractures would increase the output flow rate, so the reservoir stimulation scale increases by 0.85% and the heat extraction rate increases 0.2 MW; CO2 has better heat extraction properties than water due to its lower viscosity, greatly improving the production efficiency. Combining the hydraulic fracture conductivity tests creatively, the sensitivity analysis of fracturing parameters is studied. The heat extraction rate decreases with the increase in fracture aperture and fracture permeability. Under certain closure pressure (40 MPa in this paper), the best ceramsite proppant concentration and proppant size are 5 kg/m2 and 100 mesh, respectively, and the corresponding fracture conductivity is 1.6 μm2•cm.

Sensitivity Analysis of the Influence of Fracturing Spacing in the Construction of Complex Fractures Network for Exploration and Production of Shale Gas/Shale Oil

Shales reservoirs have a high degree of anisotropy due to the presence of natural fractures (NFs) and also the orientation of beddings. Thus, hydraulically induced fractures (HFs) interact with natural fractures and generate a network of fractures with complex geometry. The existence of NFs modifies the stress field in the shale and directly influences the geomechanical behaviour of the HFs during the fracturing operation, generating branches in the dominant fracture and contributing to the complex network of fractures. The construction of a network of fractures increases significantly the conductivity of the formation, as it connects previously isolated fractures and pores, thus increasing the productivity index of the wells and providing greater economic viability in the shale gas/oil reservoir designs. This work presents a sensitivity analysis of the influence of fracturing spacing in the construction of the network of complex fractures generated in shales, aiming to understand how this parameter modifies the volume of stimulated reservoir (SRV) and the distribution of propant in the network of fractures, in order to avoid problems in this step of the design and thus, maintain the economic viability of the network. The literature review includes the main published works on this subject and the unconventional fracture models (UFM) used to model the network of complex fractures. Sensitivity analysis will be performed using the MShale software, which uses a stochastic model of the discrete fracture network (DFN) method and numerically solves the equilibrium equations and pore elasticity for shales in terms of effective stresses, in addition to mass conservation equations, linear momentum and energy with viscous dissipation for stokes creeping flow. For the analysis, the other parameters that influence the construction of the network will be kept constant and only the spacing between fracturing will have variation.

Numerical assessment of the maximum operating pressure for SAGD projects considering the effects of anisotropy and natural fractures

There has been an increasing awareness of the importance of caprock integrity during Steam Assisted Gravity Drainage (SAGD) operations. However, mathematical tools that have been developed for caprock integrity studies have not incorporated an important characteristic of cap shales, which is the intrinsic anisotropy and structural anisotropy caused by the natural fractures (NFs) in the cap shale. This paper addresses the effects of the intrinsic anisotropy of the shales and also the existence of NFs on the Maximum Operating Pressure (MOP) in SAGD projects.In this study, a new constitutive model is developed and incorporated to consider the effect of NFs and intrinsic anisotropy in the cap shale. A coupled numerical tool was utilized to determine the MOP for different case scenarios in the number of fracture sets, fracture density and dip angle, as well as the height. Results of all cases were analyzed to evaluate their effect on the MOP.Results of the coupled model indicate continued integrity of the caprock for the case study project for the current operational program for almost all the considered case scenarios, except for an extreme case. Therefore, higher injection pressures than the current pressure were investigated to assess the MOP. Results indicate that the MOP was highly sensitive to the fracture density, direction, and height. Results also display a minor impact for the horizontal fractures on the MOP for the case study while fractures with the dip angle between 25° and 65° show a significant impact on the caprock integrity, hence, the MOP. Moreover, results indicate an overestimation of the MOP by up to 23% when neglecting the NFs. Comparing the results of different case scenarios with those of conventional isotropic models highlights the requirement to include the effect of NFs in caprock integrity studies.

Shale gas simulation considering natural fractures, gas desorption, and slippage flow effects using conventional modified model

This paper presents the theory and application to modify the conventional simulator to describe the effects of gas adsorption and gas slippage flow in shale gas. Because of the local desorption of gas and the assumptions of gas desorption instantaneously with the decrease in pore pressure, we define one fictitious immobile “pseudo” oil with dissolved gas. The dissolved gas–oil ratio is calculated from the Langmuir adsorption isotherm constants and shale gas properties. Additional modifications required in the input data are the porosity and relative permeability curves to account for the existence of “pseudo” oil. The input rock table considers the changes of rock permeability versus pressure to describe the gas slippage flow effects. In addition, dual-porosity dual-permeability models coupled with local grid refinement method are used to distinguish the impacts of natural fractures and hydraulic fractures on shale gas production with the comparison of vertical well, fractured vertical well, horizontal well, and multistage fractured horizontal well production. This proposed simulation approach shows enough accuracy and outstanding time efficiency. Results show that ignoring gas desorption and slippage flow effects would bring significant error in shale gas simulation The existence of natural fractures also imposes great effects on the productivity of shale gas.

Production rate analysis of multiple-fractured horizontal wells in shale gas reservoirs by a trilinear flow model

Most multiple-fractured horizontal wells experience long-term linear flow due to the ultralow permeability of shale gas reservoirs. Considering the existence of natural fractures caused by compression and shear stresses during the process of tectonic movement or the expansion of high-pressure gas, a shale gas reservoir can be more appropriately described by dual-porosity medium. Based on the assumption of slab dual-porosity, this paper uses the trilinear flow model to simulate the transient production behavior of multiple-fractured horizontal wells in shale gas reservoirs, which takes the desorption of adsorbed gas, Knudsen diffusion and gas slippage flow in the shale matrix into consideration. Production decline curves are plotted with the Stehfest numerical inversion algorithm, and sensitivity analysis is done to identify the most influential reservoir and hydraulic fracture parameters. It was found that the density and permeability of the natural fracture network are the most important parameters affecting the production dynamics of multiple-fractured horizontal wells in shale gas reservoirs. The higher the density and permeability of the natural fractures are, the shorter the time is required to exploit the same amount of reserve, which means a faster investment payoff period. The analytical model presented in this paper can provide some insight into the reserve evaluation and production prediction for shale gas reservoirs.

The effect of natural fractures on hydraulic fracturing propagation in coal seams

The purpose of hydraulic fracturing is to improve the gas permeability of a coal seam by the high-pressure injection of fracturing fluid into cracks. Some promising results of hydraulic fracturing in a coal seam using isotropic and intact model have been published in our previous study (Wang et al., 2014), based on which further research is necessary for the reason that natural coal is anisotropic, inhomogeneous, inelastic, and characterized by multiple discontinuities, which can be one of the most important factors governing the deformability, strength and permeability. It is difficult to accurately identify and predict the manner in which hydraulic fractures initiate and propagate because of the pre-existing natural fractures. In this paper, five typical coal models—intact coal, layered jointed coal, vertical jointed coal, orthogonal jointed coal, and synthetic jointed coal—are established to simulate hydraulic fracturing in coal seam based on two-dimensional particle flow code (PFC2D). The effect of natural existing fractures on fluid-driven hydraulic fracture is investigated by analyzing the variation of fracture radius, cumulative crack number, and growth rate of porosity versus injection time. It is shown that the existence of natural fractures, which has a significant induced effect on the initiation and propagation of hydraulic fracture, contributes greatly to the increase of crack number and growth rate of porosity. The fracture network is greatly influenced by the interaction between hydraulic fracture and natural fractures. Natural fractures with different structural properties may result in different propagation types of hydraulic fracture, which can be categorized as capturing type, crossing type, and compound type.

Flow in multi-scale discrete fracture networks with stress sensitivity

For hydraulic fracturing in the shale reservoir, the existence of natural fractures has a great impact on the propagation of hydraulic fractures and the flow capacity of porous media. Our previous study mainly discussed the effect of different fracture parameters (i.e., orientation, aperture) on the fracture network permeability based on discrete fracture model and finite elements analyses (Liang et al., 2016). To further account for the in-situ condition, we now investigate the effect of stress sensitivity, i.e. the stress difference between hydraulic fractures and natural fractures, on flow behavior in multi-scale discrete fracture networks. A series of sensitivity experiments on both naturally and artificially fractured cores with the existence of proppants were carried out. Fracture models at different scale were established based on the corresponding mathematical fitting models, to study the effect of stress sensitivity on the seepage process. Results show that with the increase of confining pressure, the permeability of natural fractures decreases exponentially while the permeability of hydraulic fractures decreases more slowly following the cubic polynomial law. The stress sensitivity of natural fractures has more influence on the flow dynamics than that of hydraulic fractures, and this difference is subject to the fracture orientation, fracture length, and intersection relationship. When the fracture orientation is parallel to pressure gradient or the fracture can serve as part of the main channel, the stress sensitivity has great impact on the productivity of the fracture network. The drainage area around the hydraulic fractures are almost the same irrespective of the stress, but the drainage area of natural fractures changes significantly when considering stress sensitivity. Therefore, it is necessary to incorporate the stress effect on the flow conductivity of hydraulic and natural fractures while modeling complex fractured reservoirs.

Breaking Up Is Hard To Do: Creating Hydraulic-Fracture Complexity in the Bakken

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 163827, ’Breaking Up Is Hard To Do: Creating Hydraulic-Fracture Complexity in the Bakken Central Basin,’ by C. Mark Pearson, SPE, Larry Griffin, SPE, and Chris Wright, Liberty Resources, and Leen Weijers, SPE, Liberty Oilfield Services, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, 4-6 February. The paper has not been peer reviewed. Drilling the Bakken in North Dakota has increased dramatically over the past several years as operators sought to hold acreage and create value with the drill bit. Much of this activity has been in the central-basin portion of the Williston basin where wells drilled before 2008 were uneconomic. Advances in completion technology caused a fundamental shift in economics, and the whole central-basin area, greater than 2,500 sq miles, has approximately 100 rigs drilling. The greatest change in completion design was incorporating high-intensity multistage fracturing. The Bakken completion design is different from other shale-gas developments, with the widespread use of uncemented liners with external packers in the openhole lateral to create the multistage zonal isolation. Introduction The Bakken formation (highlighted in red in Fig. 1) is part of the Williston basin, which spans southern Saskatchewan and Manitoba in Canada into North Dakota and Montana in the United States. The basin was formed as a subtle down- warping between the Superior craton to the northeast and the Wyoming craton to the southwest. The Williston basin is a gently dipping basin with very little structural deformation, except for a few structural features including the Nesson anticline and the Cedar Creek anticline, shown in Fig. 1. The Upper and Lower Bakken shales are prolific source rocks for the petroleum system. The middle member consists of five to seven distinct lithofacies that range from silty sandstone on the east flank of the basin to silty dolomite on the west flank. Porosities in the middle member range from 4 to 10%, and permeabilities generally are less than 0.1 md. Development History The first Bakken-formation well came on production in 1953, 2 years after first oil production in North Dakota. Over the next 15 years, a total of 42 vertical wells were completed in the Middle Bakken or Three Forks formations. Commercial production required the existence of natural fractures associated with the uplift and could be correlated to the second- derivative curvature in the formation.

High-Density Acid Used in a Deep HP/HT Well

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142033, ’Study and Application of High-Density Acid in a Deep HP/HT Well,’ by Xingsheng Cheng, Yongping Li, Yunhong Ding, SPE, and Mingguang Che, Langfang Branch, Research Institute of Petroleum E&D, PetroChina, and Fuxiang Zhang, SPE, and Jianxin Peng, Tarim Oilfield Company, PetroChina, prepared for the 2011 SPE European Formation Damage Conference, Noordwijk, The Netherlands, 7-10 June. The paper has not been peer reviewed. The KKY reservoir in the Tarim oil field in western China is a deep high-pressure/high-temperature (HP/HT) dolomite reservoir. The formation was damaged with heavy mud during drilling, and matrix acidizing could not clean the skin effectively. To decrease the surface treating pressure to a safe level, a new high-density-acid system was developed. Extensive laboratory testing was conducted to evaluate its corrosion-inhibition and friction-reduction capacities, rheological properties, and stability. The new weighted acid ensured successful acid fracturing of the KKY reservoir. Introduction The KKY is a deep dolomite condensate/gas reservoir at a depth greater than 6000 m with reservoir temperature and pressure of approximately 150°C and 110 MPa, respectively. The formation suffered extreme damage because of the use of heavy mud and the existence of natural fractures. At first, matrix acidizing was used to eliminate the skin, but treatments were limited by the high pressure required. Production increased somewhat, but dropped quickly and could not be sustained. Analysis showed that matrix acidizing could not remove the damage completely; therefore, acid fracturing was investigated. It was determined that an acid-fracturing treatment could not be implemented with conventional acid because the surface pressure exceeds the working-pressure capability of conventional 103.4-MPa fracturing equipment. A high-density-acid proposal was developed to reduce the wellhead pressure. High-Density Acid Weighting Agent. Generally, high-density acids are blended by adding acid into high-density concentrated halide brines, such as sodium chloride, calcium chloride, sodium bromide, calcium bromide, or a combination of zinc bromide and calcium bromide, among others. Because the reservoir is dolomite, the main processing acid is hydrochloric acid (HCl), and all the salts and brines mentioned above can be used. The selection of salts or brines is based primarily on the required properties of weighted acids and on cost effectiveness. Considering the need of density in the reservoir and the density of different brines, calcium chloride and some bromide were selected as weighting agent according to the properties of individual wells. The density of weighted acid can be adjusted between 1.25 and 1.55 g/cm3 by regulating the type and quantity of brine.

The influence of perturbed stresses near faults on drilling strategy: A case study in Blacktip field, North Australia

When in-situ stresses are disturbed around large scale fractures, typically faults, the direction of principal stresses can deviate from the regional trend to a completely new direction. This can have a great impact on engineering design and planning. In a gas field offshore Australia, a number of drilling difficulties and wellbore instability were reported at lower depths of one of three wells, while two wellbores in the field did not encounter similar problems. A detailed geomechanics study performed on the wellbore of interest indicated that it approached one of four major fault planes in the area as it was drilled deeper. This caused large stress anisotropy between the two horizontal stresses at lower depths, leading to a stress regime change from a normal to a strike/slip regime. The large contrast between the minimum and maximum horizontal stresses induced a number of shear failures in the form of breakouts around the wellbore, which we also observed on caliper and image logs. Accordingly, after performing sensitivity analysis on wellbore trajectory, we developed a mechanical earth model (MEM) to examine the planned well trajectories for the development campaign. The results demonstrate that the existence of natural fractures at any scale may have significant influence on in-situ stresses and stresses induced during construction of an opening.

A Semianalytical Approach To Model Pressure Transients in Heterogeneous Reservoirs

Summary Pressure-transient responses of wells in a heterogeneous reservoir are usually computed with numerical models by using fine gridding and very short timesteps. An exceptions to this practice has been the use of analytical, semianalytical, and boundary-element methods for relatively simpler forms of heterogeneity, such as layering or the existence of natural fractures. This paper presents a semianalytical approach to compute pressure transients for more-complex forms of heterogeneity including composite, layered, and compartmentalized reservoirs. In this approach, the reservoir is divided into blocks corresponding to locally homogeneous substructures, and analytical pressure-transient solutions for adjacent blocks are coupled at the boundaries. This approach is consistent with the averaging effect of pressure transients and provides an alternative to full numerical modeling of pressure-transient responses in heterogeneous formations. The validation of the approach is demonstrated in comparison to the analytical solution for horizontal wells in a homogeneous reservoir. Application examples highlight the physical consistency of the approach and demonstrate its capability to model different types of reservoir heterogeneity.