Experimental Investigation of Seepage Mechanism on Oil-Water Two-Phase Displacement in Fractured Tight Reservoir

As a type of unconventional oil and gas resources, tight sandstone reservoir has low permeability and porosity properties and thus is commonly necessary to develop through hydraulic fracturing treatment. Due to the coexistence of natural fractures and induced hydraulic fractures, the heterogeneity of reservoir permeability becomes severe and therefore results in complicated fluid seepage mechanism. It is of significance to investigate the oil-water two-phase seepage mechanics before and after the hydraulic fracturing stimulation with the aim of supporting the actual production and development of oilfield. This paper experimentally investigated the influences of fracture system on seepage characteristics of two-phase displacement in sample cores of fractured tight sandstones. In details, the changes of injection rate, cumulative production rate, recovery ratio, and water content were analyzed before and after the hydraulic fracturing treatments. To further analyze the displacement characteristics of the sample core, the displacement indices of four rock samples in different displacement stages were investigated. The sensitivity of sample core displacement indices to many key factors, including injection time, oil production rate, oil recovery factor and injection multiple factor, and moisture (i.e., water content was 95%, 98%, and 99.5%, respectively), before and after the hydraulic fracturing treatments were obtained synthetically. Besides, the relationship between recovery difference and contribution of fracture to permeability was explored at different water contents. The experimental results reveal that the fracture system shortens the water-free production period and hence reduces the recovery rate. The greater the contribution of fractures to permeability, the lower the recovery of water during this period.

A Novel Mathematical Model for Fracturing Effect Evaluation Based on Early Flowback Data in Shale Oil Reservoirs

For shale oil reservoirs, the horizontal well multistage fracturing technique is mostly used to reform the reservoir in order to achieve economic and effective development. The size of the reservoir reconstruction volume and the quantitative characterization of the fracture system are of great significance to accurately predict the productivity of shale oil wells. There are few flowback models for shale oil reservoirs. To solve this problem, first, a physical model of the simultaneous production of oil, gas, and water in the early flowback stage of shale oil development is established using the material balance equation for a fracture system. Second, the physical model of the underground fracture system is simplified, which is approximately regarded as a thin cylindrical body with a circular section. The flow of the fluid in the fracture system is approximately regarded as radial flow. In this model, the expansion of the fluid and the closure of the fracture are defined as integrated storage coefficients to characterize the storage capacity of the fracture system. Then, the curves illustrating the relationships between the oil-water ratio and the cumulative oil production and between the gas-water ratio and the cumulative gas production are drawn, and the curves are used to divide the flowback stage into an early stage and a late stage because the flowback process of shale oil wells exhibits obvious stage characteristics. Finally, the reservoir reconstruction volume and the related hydraulic fracture parameters are estimated based on the material balance method, and the rationality of the model is verified via numerical simulation. The interpretation results of this novel model are more accurate, making it an effective way to evaluate the hydraulic fracture parameters and transformation effect, and it has guiding significance for the evaluation of the hydraulic fracturing effect in the field.

Applying Boundary Element Simulation to Generate Stress-Based Fracture Drivers: A Case Study for the Montney Unconventional Oil/Gas Play in Western Canada Basin

Natural fracture distribution is critical to the hydrocarbon production from the Early Triassic Montney unconventional oil and gas play. The formation underwent several tectonic events, creating a unique natural fracture system. Identifying tectonic events and their stress field evolution is an import component in fracture system modeling and prediction. The objective of this paper is to identify the evolution of paleo-stress domains, to establish related tectonic models, and to generate the drivers for fracture network modeling which will aid in reservoir understanding and overall play development. Compared with other geomechanical approaches, the boundary element method (BEM) is better suited for the structural characteristics in the study area. Hence, the corresponding boundary element simulation (BES) was applied for the evolution of the paleo-stress domains. The methodology is a combination of 3D BEM and Monte Carlo simulations. The inputs include seismic interpreted faults and natural fractures from Formation Microimager logs. After applying the methodology, several best fit realizations were calculated, and the admissible paleo-stress domains were characterized by the tectonic models which are consistent with the regional tectonic evolution of the formation. The study area is about 400 km2 located at northeast British Columbia in the Western Canada Basin. The main structural features are the thrust and back-thrust faults, forming different fault blocks without any significant deformation structures. The Montney formation within the study area underwent several tectonic events: (1) regime of terrane collision, indentation and lateral escape during end of Middle Jurassic to Middle Cretaceous; (2) regime of left-lateral transpression dominated by strike-slip during end of Late Cretaceous and Paleocene; and (3) regime of right-lateral transtension dominated by strike-slip during end of Early and Middle Eocene which is maintained till present day. Three major stress domains were identified in the study area by the application of the BES method, one reverse event and two strike-slip events, representing paleo and present-day stress domains. These stress domains are consistent with the regional tectonic evolution history of the foreland basin. The stress field parameters, such as stress ratio and maximum horizontal stress azimuth, are consistent. The derived tectonic models are shown to be reliable drivers for the subsequent fracture modeling and geomechanics study.

Drilling Through Fractured Gas Bearing Formation to Access Previously Inaccessible Parts of an Offshore Reservoir in Abu Dhabi Using Pressurized Mud Cap Drilling - Case Study

Drilling through fractured gas bearing formations to access the oil reserves underneath has been one of the most challenging tasks for the drilling Team due to the embedded risks such as; total circulation losses, Gas migration, well control issues, hole instability, cutting beds accumulation and stuck pipe. This paper explains an approach in drilling fractured gas bearing formations that was performed for the first time in offshore Abu Dhabi field-A, Pressurized Mud Cap Drilling (PMCD). Drilling through fractured Gas bearing formation causes the loss of the mud column and the consequent intrusion of hydrocarbon gas to the wellbore, thus initiating well control response, which adds to the flat time and might cause cutting slippage, stuck pipe and eventually loss of well objective. PMCD is best suited to deal with such situation, as it allows drilling to continue under the mentioned circumstances by filling the well with sacrificial fluid while the well is closed, fractures take seawater, cuttings and the formations pressure lefts the underbalanced annular fluid to reduce losses volume. Two wells were drilled successfully using the PMCD technique in Field A where the anticipated fracture gas bearing formations system was encountered shortly below the 9-5/8″ casing shoe. The performance increased substantially in the second well as lessons learnt were implemented to avoid any time loss. Drilling the 8-1/2″ Hole section started in well #2 conventionally with required 200 psi overbalance mud weight, the drilling fluid system is directly changed to sacrificial fluid (Sea water) once the fracture system is hit and total losses observed. A light Annular mud (Seawater) is pumped in the well's annulus. After having stable PMCD parameters, drilling continued at an ROP of 100-150 FPH. TQ & Drag real-time monitoring & intermittent pumping of 3 × 50 bbls weighted HVP to clean bit & BHA from cuttings were essential to avoid getting the pipe mechanically stuck. The 6,710 ft section was drilled successfully, Striped BHA Out of hole, Ran 7,160 ft of 7″ Liner, perform cement Job & achieved isolation. Comparing with offset wells drilling conventionally in field-A through the gas bearing fractured zone, PMCD saved +/− 44 days of the well time, cost and achieved the target. and greatly improved the operational safety by providing closed-loop drilling. The PMCD application on the two wells is the first of its type in offshore Abu Dhabi, it allowed accessing parts of the reservoir that have been inaccessible due to the fracture system. Additionally, it increased safety of operation & saved rig days that would have been spent in treating losses and well control operation. Pressurized Mud Cap Drilling application in field-A provides a solution for a wider implementation in developing fractured gas cap resources in future.

The Establishment of Ore-Controlling Fracture System of Baoginshan Gold Mine Based on Fracture-Tectonic Analysis

The Baoginshan quartz vein type gold mine in the Baimashan-Longshan-Ziyunshan gold belt is the object of study, and the nature of the fracture structure and its ore-controlling effect are studied through surface and pit investigation, and the nature of the ore-controlling structure system and combination pattern of the Baoginshan gold mine is established. The F7 and F9 fractures in the near-east-west (EW) direction are the main fractures, which tend to the north and control the spreading of the ore zone; the northwest (NW) direction secondary tension fracture, with a dominant yield of 221°∠63°, is a T-type fracture in the Riedel shear mode and is the ore-holding structure of the vein-like ore body; the northeast-east (NEE) direction secondary shear fracture, with a dominant yield of 343°∠53°, is a P-type fracture and the combination of the two controls the specific positioning of the ore body. The characteristics and nature of the fracture structures in the whole ore zone, as well as their combination patterns, indicate that the overall ore-controlling fracture system of Baoginshan is a right-going tensional shear fracture zone composed of NW-oriented (T-type) and NEE-oriented (P-type) secondary fractures with F7 and F9 fractures as boundary fractures. The directions of the principal stresses are σ1≈158°∠40°, σ2≈288°∠38°, and σ3≈42°∠28°, respectively. In the next step of the prospecting process, based on increasing the spacing of prospecting pits (to 40m), in-pit drilling is deployed in the upper and lower discs of the NEE secondary fracture along with the tendency and strike for literacy, which can significantly improve the efficiency and effectiveness of prospecting and greatly reduce the cost of prospecting.

Fracture system characterisation and implications for fluid flow in volcanic and metamorphic rocks

<p>Fluid flow pathways in volcanic and metamorphic rocks are dominantly controlled by fracture systems. Although these fracture systems are critical for developing reservoirs in an economical and sustainable way, and for understanding processes that cause earthquakes, they are often poorly constrained. This thesis studies the geometry of fracture systems, the factors influencing their geometries, and their possible impacts on permeability in three contrasting settings: an outcropping andesite lava flow of the Ruapehu volcano; the andesite-hosted Rotokawa geothermal reservoir; and the Alpine Fault hangingwall metamorphosed schists. We use datasets from a combination of cores, acoustic borehole televiewer (BHTV) logs, outcrop scanlines, and terrestrial laser scanner (TLS) point clouds, which span multiple scales of observation. Fracture geometries are studied in a young (~6 ka-old) blocky andesitic lava flow on the Ruapehu volcano, as a representative example of weakly-altered andesitic lava flows emplaced over gentle topography in the absence of glaciers. Fractures were formed during cooling and emplacement of the lava flow. Fractures are automatically detected from the 3-D TLS point cloud of an outcrop area of ~3090 m2 using a plane detection algorithm, and calibrated with manual scanlines and high-resolution panoramic photographs. Column-forming fractures dominate the fracture system, are either sub-horizontal or sub-vertical (i.e., sub-parallel or sub-perpendicular to the brecciated margins) without mean strike orientation, and have an exponential length distribution. Sub-horizontal, clustered platy fractures sub-parallel to the flow direction arrest or deflect column-forming fractures. Areal and volumetric fracture intensity analyses reveal a ~0.5 % connected fracture volume which, although seemingly small, promotes fluid flow due to the planarity and connectivity of the system. Autobreccias are partially connected to column-forming fractures, and may promote lateral flow or form barriers depending on the extent of post-cooling alteration and mineralisation. Discrete fracture network models generated with the measured geometrical parameters are in agreement with the observed highly connected fracture system. Fractures in the andesite-hosted Rotokawa Geothermal Field are described in cores and BHTV logs. Fractures interpreted on BHTV logs are separated into sets of similar orientation using quantifiable clustering algorithms. Fracture thickness and spacing probability distributions are estimated from maximum likelihood estimations applied to truncated distributions, taking sampling biases into consideration. Spacing of the predominant sub-vertical NE-SW-striking fracture set, and subordinate NW-SE-striking fracture set, are best approximated by log-normal distributions and interpreted to be controlled by stratifications within the lava flow sequence. By contrast, spacing of other subordinate fracture sets, either dipping 60° and striking NE-SW, or steeply dipping and striking N-S, are best approximated by power-law distributions and interpreted to be fault-controlled. Fracture thicknesses in both cores and BHTV logs are approximated by a single power-law distribution, which reflects heterogeneous pathways observed at reservoir scale. Previously reported ~5 µm-thick fractures studied in thin section do not follow this power-law distribution and have an isotropic orientation, which suggests a change of controls on fracture density and orientation from thermal stresses at thin-section scale, to tectonic and lithological at core and BHTV log scales. However, fractures occupy ~5 % of the rock mass at the three scales of observations, suggesting a self-similar behaviour of fracture volumes in 3-D. In contrast to the Ruapehu and Rotokawa reservoir studies, scientific drilling in 2014 of the DFDP-2B borehole offered a unique opportunity to investigate the foliation and fractures along a 630 m-long borehole section in metamorphic rocks in the hangingwall of the Alpine Fault. BHTV log interpretation reveals a constant foliation and foliation-parallel fracture orientation (60°/145°; dip magnitude/dip direction) similar to nearby outcrops and parallel to the regional strike of the Alpine Fault. This foliation orientation may reflect the orientation of the Alpine Fault at ~1 km depth. In addition, sub-vertical fractures striking NW-SE above ~500 m, and sub-horizontal fractures between ~ 500-820 m below ground, are interpreted as exhumation-related joints and inherited hydrofractures respectively. Finally, we recognise metre-thick fault zones similar to those identified from BHTV logs and cores in the nearby DFDP-1B borehole. The three fracture set orientations, and observed fault zones, promote high hydraulic connectivity in the Alpine Fault hangingwall, which fosters fluid flow. This thesis helps quantify the geometrical parameters of fractures and their associated uncertainties in non-sedimentary settings, which are required to constrain numerical models and unravel fluid flow pathways in heterogeneous rocks. We identified lithological, tectonic and thermal controls on fracture geometries, which can constrain conditions and processes by which these fractures formed, and improve the prediction of fracture system architecture away from sparse borehole observations. The results of this thesis are relevant to similar lithological and tectonic settings elsewhere where observations are scarce. This study has also yielded an essential fracture dataset for better understanding of the structural and hydrological conditions at depth near the Alpine Fault prior to a large earthquake.</p>

Fracture system characterisation and implications for fluid flow in volcanic and metamorphic rocks

<p>Fluid flow pathways in volcanic and metamorphic rocks are dominantly controlled by fracture systems. Although these fracture systems are critical for developing reservoirs in an economical and sustainable way, and for understanding processes that cause earthquakes, they are often poorly constrained. This thesis studies the geometry of fracture systems, the factors influencing their geometries, and their possible impacts on permeability in three contrasting settings: an outcropping andesite lava flow of the Ruapehu volcano; the andesite-hosted Rotokawa geothermal reservoir; and the Alpine Fault hangingwall metamorphosed schists. We use datasets from a combination of cores, acoustic borehole televiewer (BHTV) logs, outcrop scanlines, and terrestrial laser scanner (TLS) point clouds, which span multiple scales of observation. Fracture geometries are studied in a young (~6 ka-old) blocky andesitic lava flow on the Ruapehu volcano, as a representative example of weakly-altered andesitic lava flows emplaced over gentle topography in the absence of glaciers. Fractures were formed during cooling and emplacement of the lava flow. Fractures are automatically detected from the 3-D TLS point cloud of an outcrop area of ~3090 m2 using a plane detection algorithm, and calibrated with manual scanlines and high-resolution panoramic photographs. Column-forming fractures dominate the fracture system, are either sub-horizontal or sub-vertical (i.e., sub-parallel or sub-perpendicular to the brecciated margins) without mean strike orientation, and have an exponential length distribution. Sub-horizontal, clustered platy fractures sub-parallel to the flow direction arrest or deflect column-forming fractures. Areal and volumetric fracture intensity analyses reveal a ~0.5 % connected fracture volume which, although seemingly small, promotes fluid flow due to the planarity and connectivity of the system. Autobreccias are partially connected to column-forming fractures, and may promote lateral flow or form barriers depending on the extent of post-cooling alteration and mineralisation. Discrete fracture network models generated with the measured geometrical parameters are in agreement with the observed highly connected fracture system. Fractures in the andesite-hosted Rotokawa Geothermal Field are described in cores and BHTV logs. Fractures interpreted on BHTV logs are separated into sets of similar orientation using quantifiable clustering algorithms. Fracture thickness and spacing probability distributions are estimated from maximum likelihood estimations applied to truncated distributions, taking sampling biases into consideration. Spacing of the predominant sub-vertical NE-SW-striking fracture set, and subordinate NW-SE-striking fracture set, are best approximated by log-normal distributions and interpreted to be controlled by stratifications within the lava flow sequence. By contrast, spacing of other subordinate fracture sets, either dipping 60° and striking NE-SW, or steeply dipping and striking N-S, are best approximated by power-law distributions and interpreted to be fault-controlled. Fracture thicknesses in both cores and BHTV logs are approximated by a single power-law distribution, which reflects heterogeneous pathways observed at reservoir scale. Previously reported ~5 µm-thick fractures studied in thin section do not follow this power-law distribution and have an isotropic orientation, which suggests a change of controls on fracture density and orientation from thermal stresses at thin-section scale, to tectonic and lithological at core and BHTV log scales. However, fractures occupy ~5 % of the rock mass at the three scales of observations, suggesting a self-similar behaviour of fracture volumes in 3-D. In contrast to the Ruapehu and Rotokawa reservoir studies, scientific drilling in 2014 of the DFDP-2B borehole offered a unique opportunity to investigate the foliation and fractures along a 630 m-long borehole section in metamorphic rocks in the hangingwall of the Alpine Fault. BHTV log interpretation reveals a constant foliation and foliation-parallel fracture orientation (60°/145°; dip magnitude/dip direction) similar to nearby outcrops and parallel to the regional strike of the Alpine Fault. This foliation orientation may reflect the orientation of the Alpine Fault at ~1 km depth. In addition, sub-vertical fractures striking NW-SE above ~500 m, and sub-horizontal fractures between ~ 500-820 m below ground, are interpreted as exhumation-related joints and inherited hydrofractures respectively. Finally, we recognise metre-thick fault zones similar to those identified from BHTV logs and cores in the nearby DFDP-1B borehole. The three fracture set orientations, and observed fault zones, promote high hydraulic connectivity in the Alpine Fault hangingwall, which fosters fluid flow. This thesis helps quantify the geometrical parameters of fractures and their associated uncertainties in non-sedimentary settings, which are required to constrain numerical models and unravel fluid flow pathways in heterogeneous rocks. We identified lithological, tectonic and thermal controls on fracture geometries, which can constrain conditions and processes by which these fractures formed, and improve the prediction of fracture system architecture away from sparse borehole observations. The results of this thesis are relevant to similar lithological and tectonic settings elsewhere where observations are scarce. This study has also yielded an essential fracture dataset for better understanding of the structural and hydrological conditions at depth near the Alpine Fault prior to a large earthquake.</p>

The deformation history of southern England, and its implications for ground engineering in the London Basin

Structures in the basement beneath the London Basin affect the geology of relevance to geotechnical engineering within London. Unfortunately, the basement beneath London is covered by Cretaceous and Tertiary sediments. It is cut by major faults linked to the compressive phases of the Hercynian and Alpine Orogenies and to the regional extension that occurred during the Mesozoic between these compressive events. Evidence is presented that movement on basement fractures beneath London played a major role in the distribution and deformation of sediments within the Basin, causing local folding and faulting significant to engineering works. Basement rocks are exposed in SW England where the type and orientation of these fractures (faults and joints) can be examined in outcrop. This study, complemented by seismic sections in the southern UK, enable the architecture of this fault network within the basement to be determined. Understanding the fracture system in the basement provides a basis for (i), interpreting the lateral facies variations of sediments in the Basin and hence provides a means for predicting from a ground investigation the likely presence, activity or influence on site of such structures at depth and (ii), understanding the extent of local, steeply inclined and sub-horizontal planar zones of shearing when encountered on site.Thematic collection: This article is part of the Geology of London and its implications for ground engineering collection available at: https://www.lyellcollection.org/cc/london-basin

Well Performance Evaluation of Carbonate Reservoirs After a Novel Hybrid Volume Stimulation Treatment

A large proportion of gas and oil resources are trapped in carbonate reservoirs. Efficient development of these formations is crucial for world energy supply. Recently, a novel hybrid volume stimulation (HVS) technique has been proposed and enhanced carbonate reservoir production in the Bohai Bay Basin and the Ordos Basin of China (Cai et al., 2015; Chu, 2017). This technique involves three stages, including pad-fluid fracturing (primary fracture and fracture branch initiation), massive acid fracturing (acid etching and connection of natural and induced fractures), and proppant injection (conductivity maintenance). Compared with conventional acid fracturing, HVS generates a more complex fracture system by taking the advantage of both hydraulic fracturing and acid fracturing, mitigating high-temperature effects, and increasing the acid penetration distance. Currently, no existing models can predict the pressure and rate behavior of wells after HVS treatments due to the complex fracture geometry and the complicated flow pattern. This study presents a multi-region linear flow model to facilitate evaluating well performance of carbonate reservoirs after HVS and obtaining a better understanding of key factors that control well responses. The model incorporates the fundamental characteristics of the complex fracture system generated by HVS. The primary hydraulic fracture is characterized by two flow regions. One is for the propped primary fracture segment (region 1), while the other represents the unpropped but acid-etched primary fracture tip (region 2). The region adjacent to the primary fracture (region 3) denotes acid-etched fracture branches. Because the acid usually cannot fully penetrate the hydraulic-fracturing-induced branches, the fractal theory is employed to depict the properties of the small fracture branches beyond the acid-etched sections. Finally, the unstimulated reservoir is described by a dual-porosity region (region 4) with vug and matrix systems. Specifically, triple-porosity region 3 contains two possible flow scenarios: one is from vugs to matrices, to fracture branches, and to the primary fracture, while the other is from vugs to matrices, and to the primary fracture. Two weighting factors are utilized to describe the proportion of reservoir volume that is involved in the two fluid flow scenarios. These flow regions are coupled through flux and pressure continuity conditions. The degenerated form of this model is verified against a published analytical model. A good agreement has been achieved between the results of the two models. Analysis results show that four flow regimes can be identified in the log-log type curve. Compared with classical type curves of fractured wells, there is a distinctive fracture-branch-affected transient regime in the pressure derivative curve with a slope between one-half and unity. The HVS generated complex fracture system enhances well productivity from the inter-porosity flow regime to the late fracture-branch-affected transient regime. The impacts of various fracture and reservoir properties on pressure and rate behavior are also documented.