Open Natural Fractures Research Articles

The influence of major faults and fractures on the development of non-matrix porosity system in a pre-salt carbonate reservoir, Santos Basin – Brazil

Faults and fractures are central for characterizing the permeability distribution in carbonate reservoirs since they act as pathways for diagenetic fluids that often favor intense rock dissolution and permeability. Usually, high permeability zones and fractures are not easily recognized in seismic data due to limited resolution and they are often associated with higher concentrations of hydrocarbons or even significant fluid losses during drilling, thus creating a challenge for hydrocarbon exploration. In the Santos Basin, southeast Brazil, the pre-salt carbonate reservoirs from the Barra Velha Formation (BVE) are the main hydrocarbon producers in Brazilian Atlantic margin and well-known for being extremely heterogeneous, exhibiting complex dual-porosity systems. In this study, we built a conceptual model of these fracture zones and non-matrix porosity formation that helped narrowing the understanding of these complex systems. The characterization of faults and fractures was carried out using seismic, well-logs, and borehole image data to understand the influence of these structures in the porosity formation along the Barra Velha Formation. In the study area, three fault sets were defined (F1, F2, and F3) from seismic data. F1 represents to the larger faults, while the F3 fault set represents the smaller faults related to the reactivation of F1; both sets being oriented NE-SW. The F2 fault set is associated with the rift formation and is oriented to NNE-SSW. These three fault sets compartmentalized the studied area into different domains, each exhibiting distinct fracture sets. The natural open fractures were formed during the reactivation of rift faults and are oriented mainly NW, NNE-NNW, NE, and ENE and were identified across the entire study area, but with different intensity values. The fracture intensity closely relates to the distance from major faults where the wells with the highest fracture intensity occurs located 150–590 m from the larger F1 fault set. Scan-lines were conducted throughout the area to determine the fault width, and an average value of 1.2 km was established. Seven non-matrix porosity classes were characterized and classified into stratigraphically concordant and discordant non-matrix pore types at well scale through borehole image interpretation. The Barra Velha Formation exhibit higher occurrence of stratigraphically discordant non-matrix porosity related to fractured zones while stratigraphically concordant non-matrix porosity is mainly controlled by the paleotopography of the study area. Overall, non-matrix porosity formation tends to follow an orientation that suggests a preferential dissolution flow towards NE and ENE directions. Intervals with higher silica content shows a positive correlation with both fracture intensity and stratigraphically discordant non-matrix porosities. This work provides a conceptual model about the fractures and non-matrix porosity distribution in pre-salt carbonate rocks that can help address some of associated structural and stratigraphic uncertainties during field appraisal and development.

Geomechanical modeling to assess the injection-induced fracture slip-potential and subsurface stability of the Cambro-Ordovician reservoirs of Hassi Terfa field, Algeria

The in-situ stress state and the distribution of the critically stressed fractures have significant implications on optimum wellbore placement, production enhancement, fluid injection, and induced seismicity which largely influence the reservoir management strategies. This study presents a comprehensive geomechanical modeling to infer the likelihood of shear slippage of the optimally oriented weak planes in response to water injection in the deep Paleozoic oil reservoirs from the Hassi Terfa field, central Algerian Sahara. The ‘B-quality’ compressive failures, i.e., breakouts from the acoustic image log indicate the maximum horizontal stress azimuth as N114°E. The inferred in-situ stress magnitudes indicate a strike-slip tectonic regime in the study area. The reservoir is generally tight (porosity <8 %, permeability <0.4 mD) due to extensive silica cementation, however pre-existing closed to partially open natural fractures of variable geometries are identified on cores, thin sections, and image logs. The stress-based slip assessment indicates that none of the fracture geometries is critically stressed and hydraulically conductive at the initial reservoir stress state. The onset of slip on the critically oriented vertical fractures can initiate at 1200 psi of fluid injection at the reservoir level of ∼3500 m. The E-W to EES-WWN oriented fractures, parallel to the maximum horizontal stress azimuth, have a higher likelihood of being critically stressed during injection and therefore can contribute to the permeability enhancement. We restrict the practical injection threshold at 3000 psi, which can create tensile failures on the shale caprocks. We infer that the NE-SW and NNE-SSW striking, steeply dipping fractures and regional faults being perpendicular or at high angles to the regional maximum horizontal stress azimuth, are the most stable ones and therefore, less likely to slip within the practical injection limit.

Investigation of Natural Weak Interface Properties and Their Impact on Fracture Propagation in Shale Reservoirs

Horizontal well multi-cluster fracturing technology is crucial for the economic development of fractured shale reservoirs. The abundance of natural fractures in shale reservoirs significantly influences the propagation path of hydraulic fractures and determines the formation of complex fracture networks. To investigate the impact of natural weak planes on the geometric parameters of fractures in shale reservoirs, we first conducted tests on the mechanical characteristics of core samples from outcropping shale in the Weiyuan area using the indoor three-point bending method and digital image correlation (DIC) technology, providing data validation for subsequent numerical models. Secondly, considering the interaction between hydraulic and natural weak planes in three-dimensional space, we established a three-dimensional numerical model for horizontal well fracturing to simulate the synchronous competition and expansion of fractures in multi-cluster fracturing. Based on this foundation, we analyzed the influence of formation parameters and engineering parameters on the formation patterns of complex fracture networks. The results indicate that the difference in in situ stress is a significant factor affecting the selection of fracture propagation paths. As the in situ stress difference increases, it becomes more challenging to open natural fractures, leading to a reduced probability of activation of natural weak interfaces. When the cohesive strength of natural fractures is smaller, they are more likely to open and capture hydraulic fractures, thereby increasing shear slip length and fracture network area. Each fracturing stage has an optimal perforation density combination, where a higher density of perforations leads to reduced perforation pressure drop and weaker ability to mitigate inter-cluster stress interference. To achieve a comprehensive and balanced development of multi-clusters, the inter-cluster stress interference can be alleviated by increasing the perforation pressure drop. For dense perforation clusters, higher injection rates and viscosity can be employed to ensure the uniform development of multiple perforation clusters. This study provides new insights into predicting the formation of complex fracture networks in shale reservoirs and offers valuable guidance for optimizing hydraulic fracturing designs.

Anatomy of fractures: Quantifying fracture geometry utilizing X-ray computed tomography in a chalk-marl reservoir; the Lower Cretaceous Valdemar Field (Danish Central Graben)

Naturally fractured reservoirs tend to show heterogeneous permeability with open fractures enhancing the inherent diagenetic and depositional matrix fabric. Natural open fractures may function as pathways for fluid flow in tight (low matrix permeability) carbonate reservoirs and have a significant impact on the directions, magnitudes and heterogeneities of fluid flow and reservoir rock strength. Open fractures may however also facilitate the invasion of formation water while fractures that are partially or completely cemented can act as barriers to fluid flow. As a result, natural fractures significantly impact reservoir flow rates, anisotropy, storage, connectivity, recovery, and production. X-ray Computed Tomography (CT) offers a non-destructive technique to evaluate petrophysical parameters, such as porosity and permeability, and to assess the geometry, connectivity, and density of natural fractures, which are important constituents of chalk reservoirs. The purpose of this study is to investigate different types of naturally occurring fractures within the Lower Cretaceous succession of the Valdemar Field in the Danish North Sea. Six samples of core displaying at least one natural fracture on the surface are imagined; two samples of open fractures with plumose structure and hackle marks, three samples of shear fractures and finally one sample with deformation bands. The samples are imaged by CT and internal fractures are manually mapped. Image analysis provides detailed information on the fracture geometry in addition it indicates the presence of numerous microfractures hitherto not recorded in the Lower Cretaceous of the Danish North Sea. Core data show that fracture intensity can be significantly greater than calculated by conventional core interpretation techniques based on core surface observations. Further, apertures of both major and minor fractures are measured in CT images of all samples to determine if specific fracture types display characteristic that can distinguish them from other fracture types. As open fracture intensity increases, so too does permeability, likely enhancing reservoir connectivity on the field scale.

The characteristics of natural open fractures in acoustic borehole image logs from the pre-salt Barra Velha formation, Santos Basin, Brazil

Natural open fractures have been reported in the Barra Velha Formation (BVE) in the pre-salt lacustrine carbonate reservoirs in the Santos Basin offshore Brazil. These fractures contribute to excess permeability i.e., well test permeability is significantly larger than core permeability or log derived permeability, and they are therefore important for the fluid flow in the reservoirs during production and injection. In this paper we summarize the characteristics of natural open fractures in acoustic borehole image logs (BHI) in 19 wells from the BVE reservoirs and discuss their distribution, occurrences and formation. The data quality is overall good and consistent so that results can be compared between wells. The P21 fracture intensity, which is fracture trace length per area (bore hole wall) was used, instead of Terzaghi corrected P10 fracture intensity which do not distinguish between minor and major fractures. Mean P21 fracture density shows a variation of 2 orders of magnitude between interpreted wells. Data binning was used in the analysis of P21 fracture intensity vs petrophysical parameters to reduce the effect of sampling volume being much smaller than the representative elementary volume (REV) of the fracture pattern. P21 fracture intensity shows a positive correlation with silica content, which varies in the carbonates, whereas the porosity is less important for fracture intensity. The occurrence of fractures is also associated with vug-fraction estimated from the acoustic BHIs. Fractures are also frequent in fault damage zones, above and below cavities. The main orientation of the fractures is NNW-SSE, that is in the same direction as the dominating fault trend, and this indicates a structural control on fracture formation. Natural open fractures are rare in high porosity rocks with a shrubby or grainy texture, and also in intervals with a conglomeratic appearance in the BHI image logs.

Fracture permeability estimation utilizing conventional well logs and flow zone indicator

Characteristics of the natural open fractures on the oil and gas reservoirs is crucial in drilling and production planning. Direct methods of fractures studies such as core analysis and image log interpretation are usually not performed in all drilled wells in a field. Therefore, in absence of these data, the indirect methods can play an important role. In this study, an integrated algorithm is introduced to identify the fractures and estimate its permeability employing conventional well logs. First, open fractures were identified and their properties including density, aperture, porosity and permeability were estimated using FMI log. Subsequently, the fracture index log (FR_Index) was estimated utilizing conventional logs including density, micro-resistivity, sonic (compressional, shear and stoneley slownesses), and caliper logs. After that, the fracture index permeability was estimated by improving the FZI permeability equation. The coherence coefficient between two estimated fracture permeability logs is 0.66. A good correlation is observed on the high permeability zones, but the lower correlation on the low permeability zones. It is notified that, in the high fracture permeability zones, the conventional logs are heavily impacted by fracture permeability. However, due to lower vertical resolution of conventional logs compared with the image logs, the conventional logs are less influenced by less dense fracture zones. However, this algorithm can be used with acceptable accuracy in all uncored and image log wells.

Open fractures in pre-salt silicified carbonate reservoirs in block BM-C-33, the Outer Campos Basin, offshore Brazil

Natural open fractures are present in sidewall cores and in whole-core samples from pre-salt reservoirs in the licence block BM-C-33 in the Campos Basin, Brazil. Open fractures are also observed in borehole image logs, and fracture densities are in general high. The highest density of open fractures is seen in the damage zones above and below larger cavities (amalgamated cavern damage zones (ACDZs)). Outside the ACDZs the fracture density is high in silicified carbonates, where it tends to increase with decreasing porosity. Clean dolomites are less fractured than the silicified interval, while the less brittle argillaceous dolomites have the lowest fracture density. Some fractures appear vuggy on borehole image logs, and fracture densities are high close to vugs and larger cavities. The positive correlation between fractures and vugs is caused by flow of dissolving fluids through open fractures, and fracturing at stress concentrations around vugs. Two major fault zones have been interpreted from borehole image logs that have damage zones with very high fracture density. The well-test permeability is much greater than the matrix permeability estimated from sidewall core and log measurements. This excess permeability is attributed to fractures, in combination with caverns and intervals with frequent vugs.

Natural fracture opening preservation and reactivation in deep sandstones of the Kuqa foreland thrust belt, Tarim Basin

In deep to ultra-deep sandstones, natural open fracture patterns strongly influence the directions, magnitudes, and heterogeneities of fluid flow. We present an analysis of the natural fracture patterns, critically-stress state, and productivity of 35 wells in the Keshen and Dabei gas fields of the Kuqa foreland thrust belt. Our results show that reservoir performance is governed by the critical stress that acts on existing fractures to enhance their permeability. There is a good correspondence between the critically-stressed fractures and the natural open fractures in cores. These open fractures have patterns of barren cement, quartz bridges, and slickensides. Barren cement and quartz bridges indicate the preservation of permeable fractures, while the slickensides indicate shear reactivation. Barren fractures developed due to extension at the late stage of structural activities. Quartz bridge can prop up fracture walls to preserve porosity and permeability when compression. Shear reactivations consist of strike-slip and dip-slip, which broke the gypsum and calcite seal. Shear-reactivated fractures could reflect stress state transition from thrust regime to strike-slip regime during rapid burial. Combined with the analysis of fracture morphologies and kinematics, we indicate that open fractures development may relate to folding and fault reactivation. Besides, our case indicates that the E-W open fractures in the Keshen field and NE-SW open fractures in the Dabei field are not consistent with the direction of modern-day maximum horizontal compressive stress (σHmax). We conclude that the quartz bridge and shear reactivation govern the persistence of open fractures in tight and ultra-deep sandstones, even if the open fractures are perpendicular to σHmax.

The impact of natural fractures on heat extraction from tight Triassic sandstones in the West Netherlands Basin: a case study combining well, seismic and numerical data

AbstractThe positive impact that natural fractures can have on geothermal heat production from low-permeability reservoirs has become increasingly recognised and proven by subsurface case studies. In this study, we assess the potential impact of natural fractures on heat extraction from the tight Lower Buntsandstein Subgroup targeted by the recently drilled NLW-GT-01 well (West Netherlands Basin (WNB)). We integrate: (1) reservoir property characterisation using petrophysical analysis and geostatistical inversion, (2) image-log and core interpretation, (3) large-scale seismic fault extraction and characterisation, (4) Discrete Fracture Network (DFN) modelling and permeability upscaling, and (5) fluid-flow and temperature modelling. First, the results of the petrophysical analysis and geostatistical inversion indicate that the Volpriehausen has almost no intrinsic porosity or permeability in the rock volume surrounding the NLW-GT-01 well. The Detfurth and Hardegsen sandstones show better reservoir properties. Second, the image-log interpretation shows predominately NW–SE-orientated fractures, which are hydraulically conductive and show log-normal and negative-power-law behaviour for their length and aperture, respectively. Third, the faults extracted from the seismic data have four different orientations: NW–SE, N–S, NE–SW and E–W, with faults in proximity to the NLW-GT-01 having a similar strike to the observed fractures. Fourth, inspection of the reservoir-scale 2D DFNs, upscaled permeability models and fluid-flow/temperature simulations indicates that these potentially open natural fractures significantly enhance the effective permeability and heat production of the normally tight reservoir volume. However, our modelling results also show that when the natural fractures are closed, production values are negligible. Furthermore, because active well tests were not performed prior to the abandonment of the Triassic formations targeted by the NLW-GT-01, no conclusive data exist on whether the observed natural fractures are connected and hydraulically conductive under subsurface conditions. Therefore, based on the presented findings and remaining uncertainties, we propose that measures which can test the potential of fracture-enhanced permeability under subsurface conditions should become standard procedure in projects targeting deep and potentially fractured geothermal reservoirs.

Fluid flow and fault-related subsurface fractures in slate and metasandstone formations: A case study of the Jentse Geothermal Area, Taiwan

Permeable structures associated with faults are commonly treated as geothermal fluid conduits in most tight geothermal reservoirs. However, the properties of permeable structures within fault zones remain unclear due to the lack of subsurface geological data, e.g., the geothermal systems in the tight slate and metasandstone formations in Northeastern Taiwan. This study presented standard open-hole and Fullbore Formation MicroImager (FMI) logs acquired in the 8.5-inch-diameter section of the JT-3 well (800–1475 m measured depth) in the Jentse geothermal area, Taiwan, to identify the subsurface fracture structures and the possible pathway of fluid flow. Using open-hole log data, we generate a lithology interpretation for the borehole and model the associated effective porosity. Based on the FMI images, four types of natural open fractures, two types of natural sealed fractures, and drilling-induced tensile fractures were identified. Integration of the lithological model, the effective porosity, and the types of fractures reveals one major permeable fault system comprising three permeable fault zones. The fault system is composed of both permeable fault cores marked by porous fault breccia and damage zones characterized by a large number of open-fracture planes. The static borehole temperature log also shows deflections in these interpreted permeable fractures zone. Deflections in these fracture zones that, based on petrophysical and borehole image logs, are interpreted as permeable. According to the orientations of the bed boundaries and fault planes obtained from FMI images, the fault system may have an orientation of N50–70 °E and dips 70–90˚ to the NW with a width of around 116 m. This study illustrates how subsurface structures control geothermal conduits. The concept and workflow of this study may be useful for other fault-controlled geothermal areas in Taiwan.

The mechanical contrast between layers controls fracture containment in layered rocks

Open natural fractures allow fluids to flow, which is necessary for the production of low-permeable geothermal and petroleum reservoirs. These reservoirs often consist of lithological layers with significant variation in rock strength, which makes it difficult to predict fracture containment within the rock succession. In this paper, fractures are classified as contained, when they do not cross the layer interface of the adjacent layer, so that formation and growth are inhibited in the adjacent layer. This study concerns the impact of the differences in rock strength (i.e., mechanical contrast) between two adjacent brittle layers on the fracture containment in finely-layered rocks. Laboratory deformation tests and 2D finite element modelling were performed on three-layered samples with varying mechanical contrasts to examine the behaviour of fractures at different stress conditions. Fractures initiate as shear fractures in weak layers, and propagate with a steeper angle (tensile fracture) through the adjacent stronger layer. The mechanical contrast within a layered rock does not always act as a containment barrier, meaning that fractures do not cross the layer interface of the adjacent layer. This is due to differences in differential stress between the weakest layer and strongest layer. The mechanical contrast combined with the magnitude of the confining pressure has a significant influence on fracture containment. An increase in mechanical contrast and confining pressure prevents fractures from propagating into stronger layers. The results contribute to predict natural fracture containment in brittle sequences at shallow depth in the subsurface.

Using orthorhombic depth imaging to image fractures in tight reservoirs of the RDG Field, Barmer Basin, India

Raageshwari Deep Gas (RDG) Field is situated in the southern part of the Barmer Basin in Rajasthan, India, at a depth of 3000 m. With both clastic and volcanic lithologies, the main reservoirs are tight, and hydraulic fracturing is required to enhance productivity, especially to improve permeability through interaction of induced fractures with natural fractures. Therefore, optimal development of the RDG Field reservoirs requires characterization of faults and natural fractures. To address this challenge, a wide-azimuth 3D seismic data set over the RDG Field was processed to sharply define faults and capture anisotropy related to open natural fractures. Anisotropy was indicated by the characteristic sinusoidal nature of gather reflection events processed using conventional tilted transverse imaging (TTI); accordingly, we used orthorhombic imaging to correct for these, to quantify fracture-related anisotropy, and to yield a more correct subsurface image. During prestack depth migration (PSDM) processing of the RDG data, TTI and orthorhombic velocity modeling was done with azimuthal sectoring of reflection arrivals. The resultant PSDM data using this velocity model show substantial improvement in image quality and vertical resolution at the reservoir level compared to vintage seismic data. The improved data quality enabled analysis of specialized seismic attributes like curvature and thinned fault likelihood for more reliable characterization of faults and fractures. These attributes delineate the location and distribution of probable fracture networks within the volcanic reservoirs. Interpreted subtle faults, associated with fracture zones, were validated with microseismic, production, and image log data.

Numerical Investigation of Hydraulic Fracture Propagation Based on Cohesive Zone Model in Naturally Fractured Formations

Complex propagation patterns of hydraulic fractures often play important roles in naturally fractured formations due to complex mechanisms. Therefore, understanding propagation patterns and the geometry of fractures is essential for hydraulic fracturing design. In this work, a seepage–stress–damage coupled model based on the finite pore pressure cohesive zone (PPCZ) method was developed to investigate hydraulic fracture propagation behavior in a naturally fractured reservoir. Compared with the traditional finite element method, the coupled model with global insertion cohesive elements realizes arbitrary propagation of fluid-driven fractures. Numerical simulations of multiple-cluster hydraulic fracturing were carried out to investigate the sensitivities of a multitude of parameters. The results reveal that stress interference from multiple-clusters is responsible for serious suppression and diversion of the fracture network. A lower stress difference benefits the fracture network and helps open natural fractures. By comparing the mechanism of fluid injection, the maximal fracture network can be achieved with various injection rates and viscosities at different fracturing stages. Cluster parameters, including the number of clusters and their spacing, were optimal, satisfying the requirement of creating a large fracture network. These results offer new insights into the propagation pattern of fluid driven fractures and should act as a guide for multiple-cluster hydraulic fracturing, which can help increase the hydraulic fracture volume in naturally fractured reservoirs.

Well-Placement Timing, Conductivity Loss Affect Production in Multiple-Fracture Wells

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 180448, “Effects of Well-Placement Timing and Conductivity Loss on Hydrocarbon Production in Multiple-Hydraulic-Fracture Horizontal Wells in a Liquids-Rich Shale Play,” by Shameem Siddiqui, SPE, Doug Walser, SPE, and Ron Dusterhoft, SPE, Halliburton, prepared for the 2016 SPE Western Regional Meeting, Anchorage, 23–26 May. The paper has not been peer reviewed. Horizontal wells in liquids-rich shale plays are now being drilled such that lateral and vertical distances between adjacent wells are significantly reduced. In multistacked reservoirs, fracture height and orientation from geomechanical effects coupled with natural fractures create additional complications; therefore, predicting well performance using numerical simulation becomes challenging. This paper describes numerical-simulation results from a three-well pad in a stacked liquids-rich reservoir (containing gas condensates) to understand the interaction between wells and production behavior. Numerical Simulation The reservoir simulator used for this study was designed to handle unstructured-grid-based simulation cases. Most of the numerical reservoir simulators that are used for modeling horizontal wells with multiple hydraulic fractures are based on structured grid cells in which the hydraulic fractures are modeled as symmetric biwing fractures perpendicular to the wellbore. In most cases, they use local grid refinement (LGR) to incorporate the hydraulic fractures into the model, which generally works well if a single well is involved and the grids are not tied to the Earth models. However, if the wells and the hydraulic fractures are not orthogonal to the Earth-model grids or if the reservoir contains nonorthogonal secondary fractures (natural or induced), modeling them with LGR becomes a challenge. When multiple wells that are not parallel are drilled from a single pad, properly representing the wells with hydraulic fractures in a structured-grid-based reservoir-simulation model becomes even more challenging. By contrast, the unstructured-grid-based reservoir models are not restricted by any of these limitations—they can have any geometry, size, or orientation for the wells and can include primary hydraulic fractures, secondary fractures, and open natural fractures. Instead of using grid cells that are parallel in shape, the unstructured grid cells can have any arbitrary shape. Incorporating realistic induced hydraulic fractures in a reservoir model is easier if unstructured grids are used. Reservoir-Simulation Model The reservoir model consisted of five horizontal layers with varying properties in each layer. The horizontal sections of Wells 1 and 3 go through the middle of Layer 2, and that of Well 2 goes through the middle of Layer 4. Each well is completed exactly the same way.

Fracture and Stress Orientation from Borehole Image Logs: A Case Study from Cambay Basin, India

ABSTRACT The Deccan trap basalt, laid down by multiple lava flows during upper Cretaceous to Paleocene times forms the basement of current study in Cambay basin. As such, there is great interest and value in fracture detection and evaluation of fractured basement reservoirs in the Cambay basin. The procedure for identification and evaluation of natural as well as induced fractures in basaltic basement of the Cambay basin is presented in this work. In this study formation micro-imager (FMI) and extended range micro-imager (XRMI) log data for fracture identification is used. The Deccan trap basaltic basement of the study area, comprising five wells in the Tarapur-Cambay block, has potential for holding commercial hydrocarbon due to the presence of fractures and weathered basement. Both image logs (FMI, XRMI) identify three types of fracture including open (conductive), partially open and closed (resistive) fractures, of which open and partially open fractures are important for hydrocarbon accumulation. Fracture dip ranges from 10° to 80°. Image logs have also identified washout, breakout and drilling-induced fracture zones. The strike direction of the open natural fractures for four wells varies from N60°E to N30°E whereas the strike direction of most natural fracture in the fifth well is oriented towards N20°W. The orientations of drilling-induced fractures and breakouts may be interpreted for the in-situ stress direction over the logged interval. Drilling-induced tensile fractures, identified over the depth interval of 1969–1972 m, and borehole breakouts over the interval of 1953–1955 m in one well, suggest an orientation of maximum in-situ horizontal compressive stress (SH) lies in the north-south direction. The azimuths of open natural fractures in the same well vary from north-south to N30°E. It is expected that the direction of fluid flow will be controlled by open natural fractures and therefore would be in a direction parallel to the SH direction, which is orthogonal to the minimum horizontal stress (Sh) direction. The orientations observed are consistent with the present day SH direction in the study area of Cambay basin.

Identification of natural fractures using resistive image logs, fractal dimension and support vector machines

The purpose of this research is to apply a new approach to identify natural fractures in wells in a hydrocarbon reservoir using resistive image logs, fractal dimension and support vector machines (SVMs). The stratigraphic sequence investigated by each well is composed of Cretaceous calcareous rocks from the Catatumbo Basin, Colombia. The box counting method was applied to image logs in order to generate a curve representing variations of fractal dimension in these images throughout each well. The arithmetic mean of fractal dimension showed values ranging from 1,70 to 1,72 at the mineralized fracture intervals, and from 1,72 to 1,76 at the open fracture intervals. Morphological classification between open and mineralized natural fractures is performed using corelogs integration in a pilot well. Fractal dimension of images along with gamma rays and resistivity logs were employed as the input dataset of a SVM model identifying intervals with natural open fractures automatically, shortly after logs acquisition and previous to its interpretation by specialists. Although final results were affected by borehole conditions and logs quality, the SVM model showedaccuracy between 72,3% and 82,2% in 5 wells evaluated in the studied field.

Opening of natural fracture and its effect on leakoff behavior in fractured gas reservoirs

Fluid leakoff is one of the most important issues frequently encountered in hydraulic fracturing, especially in naturally fractured gas reservoirs. Opening of natural fractures will bring about excessive fluid loss and restrain the propagation of major hydraulic fractures. A mathematical model of natural fracture dominant leakoff in fractured gas reservoirs has been developed in this paper. Besides, the opening mechanism of natural fractures has been discussed and a new criterion is proposed. Simulation results indicate that open natural fractures have a dominant effect on fracturing fluid leakoff. The wider the opening of the natural fractures, the larger the leakoff of fracturing fluid. The opening of natural fractures depends not only on stress but also the hydrodynamic size of polymer molecules. Due to the formation of filter-cake, the solid phase in fracturing fluid, consisting of polymer residues, formation fines and fluid loss additives plays an important role in the fluid leakoff behavior, which could be divided into two regions, solid dominant region and reservoir dominant region. Moreover, the leakoff behaviors between slick water and cross-linked fluid are compared for shale gas reservoirs, demonstrating that it is easier for slick water to seep into natural fractures and produce a fracture network.

Integrated reservoir characterization and simulation of a shallow, light-oil, low-temperature reservoir: Umiat field, National Petroleum Reserve, Alaska

Umiat field in northern Alaska is a shallow, light-oil accumulation with an estimated original oil in place of more than 1.5 billion bbl and 99 bcf associated gas. The field, discovered in 1946, was never considered viable because it is shallow, in permafrost, and far from any infrastructure. Modern drilling and production techniques now make Umiat a more attractive target if the behavior of a rock, ice, and light oil system at low pressure can be understood and simulated. The Umiat reservoir consists of shoreface and deltaic sandstones of the Cretaceous Nanushuk Formation deformed by a thrust-related anticline. Depositional environment imparts a strong vertical and horizontal permeability anisotropy to the reservoir that may be further complicated by diagenesis and open natural fractures. Experimental and theoretical studies indicate that there is a significant reduction in the relative permeability of oil in the presence of ice, with a maximum reduction when connate water is fresh and less reduction when water is saline. A representative Umiat oil sample was reconstituted by comparing the composition of a severely weathered Umiat fluid to a theoretical Umiat fluid composition derived using the Pedersen method. This sample was then used to determine fluid properties at reservoir conditions such as bubble point pressure, viscosity, and density. These geologic and engineering data were integrated into a simulation model that indicate recoveries of 12%–15% can be achieved over a 50-yr production period using cold gas injection from five well pads with a wagon-wheel configuration of multilateral wells.

Seismic azimuthal anisotropy analysis after hydraulic fracturing

Many tight sandstone, limestone, and shale reservoirs require hydraulic fracturing to provide pathways that allow hydrocarbons to reach the well bore. Most of these tight reservoirs are now produced using multiple stages of fracturing through horizontal wells drilled perpendicular to the present-day azimuth of maximum horizontal stress. In a homogeneous media, the induced fractures are thought to propagate perpendicularly to the well, parallel to the azimuth of maximum horizontal stress, thereby efficiently fracturing the rock and draining the reservoir. We evaluated what may be the first anisotropic analysis of a Barnett shale-gas reservoir after extensive hydraulic fracturing and focus on mapping the orientation and intensity of induced fractures and any preexisting factures, with the objective being the identification of reservoir compartmentalization and bypassed pay. The Barnett Shale we studied has near-zero permeability and few if any open natural fractures. We therefore hypothesized that anisotropy is therefore due to the regional northeast–southwest maximum horizontal stress and subsequent hydraulic fracturing. We found the anisotropy to be highly compartmentalized, with the compartment edges being defined by ridges and domes delineated by the most positive principal curvature [Formula: see text]. Microseismic work by others in the same survey indicates that these ridges contain healed natural fractures that form fracture barriers. Mapping such heterogeneous anisotropy field could be critical in planning the location and direction of any future horizontal wells to restimulate the reservoir as production drops.

Scale dependence of in‐situ permeability measurements in the Nankai accretionary prism: The role of fractures

Modeling studies suggest that fluid permeability is an important control on the maintenance and distribution of pore fluid pressures at subduction zones generated through tectonic loading. Yet, to date, few data are available to constrain permeability of these materials, at appropriate scales. During IODP Expedition 319, downhole measurements of permeability within the uppermost accretionary wedge offshore SW Japan were made using a dual‐packer device to isolate 1 m sections of borehole at a depth of 1500 m below sea floor. Analyses of pressure transients using numerical models suggest a range of in‐situ fluid permeabilities (5E‐15–9E‐17 m2). These values are significantly higher than those measured on core samples (2E‐19 m2). Borehole imagery and cores suggests the presence of multiple open fractures at this depth of measurement. These observations suggest that open permeable natural fractures at modest fracture densities could be important contributors to overall prism permeability structure at these scales.