Fractured Carbonate Reservoirs Research Articles

Investigation of fractured carbonate reservoirs by applying shear-wave splitting concept

In this study, fracture orientations in carbonate reservoirs were determined using a multicomponent velocity analysis based on shear wave splitting. The analysis is based on the estimated velocities of large seismic events with different polarizations. In a fractured zone with a dominant orientation, weak amplitude split shear events, including shear noise, result in shear waves that are polarized toward the symmetry and anisotropy axes and propagate with a common fast and slow velocity, respectively. Thus, a velocity stack should show high coherency anomalies in directions parallel and orthogonal to the fracture strike. Furthermore, because the analysis is applied locally at a specific depth range, it is less susceptible to the effects of overburden anisotropy and noise. The dominant fracture orientations from carbonate reservoirs of four oilfields were compared to those interpreted from fullbore microimager and core data. Fractures in two offshore reservoirs strike NNE-SSW and NW-SE, which are related to Zagros stress. Fractures in two onshore reservoir strikes NE-SW, while in deeper onshore reservoir fractures are aligned with N-S direction. The findings of this study are promising, particularly for the fractured reservoirs especially those located in Abu Dhabi, which are characterized by high heterogeneity and complex fracture network related to complex tectonic history. In order to obtain geometrical parameters of fractures at seismic scale, it is recommended to implement the analysis adapted in this study after acquiring three component zero-offset vertical seismic profiling. Cited as: Diaz-Acosta, A., Bouchaala, F., Kishida, T., Jouini, M. S., Ali, M. Y. Investigation of fractured carbonate reservoirs by applying shear-wave splitting concept. Advances in Geo-Energy Research, 2023, 7(2): 99-110. https://doi.org/10.46690/ager.2023.02.04

Azimuthal Investigation of a Fractured Carbonate Reservoir

Summary Oil production and enhanced oil recovery in carbonate reservoirs in Abu Dhabi, UAE, are largely affected by fracture systems that control the fluid path and the permeability of reservoirs. Most fracture properties, such as fracture orientations and density, are obtained by interpreting petrophysical data acquired at the wellbores, whereas fracture properties between wells are typically derived from nonzero offset seismic data. However, deriving fracture properties from seismic data is challenging, as it requires a robust methodology and a careful seismic processing procedure. In the current case study, we used the azimuthal amplitude vs. offset (AVAz) method on 3D seismic data acquired in onshore Abu Dhabi, to generate maps of fracture orientation and density in a carbonate reservoir. A sophisticated processing series was carefully performed to increase signal-to-noise ratio (SNR) and preserve seismic amplitudes. The main parameters controlling the AVAz method were investigated and optimized before being applied to the 3D seismic data. The reservoir has a high fracture density in the lower regions, but a low fracture density in the upper parts, indicating a weaker anisotropy. The resulting dominant fracture directions span from north-northwest/south-southwest to north-northeast/south-southwest, as well as from northwest/southeast to east/west, which is consistent with the primary fracture orientations determined from the interpretation of fullbore formation microimager (FMI) data acquired at well locations. These fracture systems are the result of the Late Cretaceous obduction of the Semail ophiolite, which was oriented east/west and northeast/southwest, followed by the south/north to southwest/northeast trending Late Oligocene-Miocene continent-continent collision of the Arabian and Central Iran plates along the Zagros orogenic front.

Improvement to Gravity Drainage Recovery by Repressurization as a Criterion to Screen and Rank Naturally Fractured Reservoirs for Gas Injection

Summary Many of the naturally fractured carbonate reservoirs of the Middle East exhibit low natural-depletion recoveries. The reason is that most of their oil reserves are stored in the low-permeability host rocks and are left behind by the fast advancing gas/oil contact (GOC) and water/oil contact (WOC) in fractures. Producing the remaining oil in the large gas-invaded zone of these reservoirs has been a crucial reservoir management issue. We show in this study using experimental observations, analytical calculations, and numerical investigations that repressurizing naturally fractured reservoirs (NFRs) by crestal immiscible gas injection has the potential to produce a large portion of this remaining oil by improving gravity drainage (GD) through two main mechanisms. One is that at higher pressures, the gas-oil interfacial tension (IFT) and hence the capillary forces that control recovery by GD are lessened, allowing additional recovery. This mechanism is aided by the other one, which is swelling of the oil at higher pressures. In this way, repressurization is thought to be not only a means for pressure maintenance but also a methodology for enhanced-oil recovery (EOR). This is confirmed by both laboratory studies and field performance of large-scale gas injection projects. Despite the desire for implementation of projects of repressurization, gas availability and cost of these projects are important concerns, requiring a cost-benefit analysis. Screening and ranking methodologies have been previously presented for some EOR techniques but not for repressurization by gas in NFRs. Evaluating the performance of gas injection in NFRs is often done using methodologies such as numerical simulations, which are in-depth, costly, and tedious. The methodology developed here is simple, requiring spreadsheet calculations. To develop the methodology, we first obtain simple relations to calculate additional GD recovery by considering the interplay of capillary and gravity forces in a matrix block subjected to pressurization by equilibrium gas injection and then use experimental data from literature to show that these relations can predict primary and secondary GD recoveries to a good approximation. We also show by mechanistic studies using a history-matched numerical model that IFT reduction and oil swelling are the main mechanisms contributing to additional oil recovery. Then, we propose a methodology to screen and rank candidate NFRs for gas injection that uses commonly available reservoir data and is based upon two criteria, these being additional oil recovered from a matrix block by pressurization and required volume of gas to produce an additional barrel of oil. We then implement this methodology to more than 20 Iranian NFRs and identify six reservoirs with potential for additional recovery of more than 20%. By quantifying and including the uncertainties associated with the reservoir data, we illustrate that for the reservoirs under study, capillary pressure parameters along with matrix-block height are the main parameters affecting GD recovery and should be characterized more accurately.

Thermo-kinetic analysis and microstructural characterization of fractured-carbonate rock exposed to high temperature

A significant amount of the world oil reserves is held in naturally fractured carbonate reservoirs which can undergo temperature-induced changes in structural and physicochemical properties while applying thermal stimulation methods. This study reports thermo-kinetic and microstructural analyses of a fractured-carbonate rock from a Mexican reservoir exposed to high temperatures using thermogravimetry and X-ray micro-computed tomography. Activation energies and reaction mechanism kinetics involved in the thermal degradation of the rock sample were determined through iso-conversional and model-fitting methods. X-ray diffraction revealed the expected mineralogy of the rock sample: dolomite (96.5%) and quartz (3.5%). Results indicated that rock thermal-decomposition follows a first-order reaction kinetics with an average activation energy of 195.910 kJ/mol. Noteworthy microstructural changes were detected on the analyzed fractured-carbonate rock exposed to heat-treatment which resulted in percent increases of 7.47, 4.37 and 25.39% in total, effective and isolated porosity, respectively. Results presented in this work can be relevant for the exploitation through thermal stimulation methods of naturally fractured carbonate reservoirs.

Foaming supramolecular surfactants for gas mobility control in naturally fractured carbonate reservoirs at high temperature, salinity, and hardness

Oil production and maintenance are essential issues in naturally fractured reservoirs because they are the largest and most productive on earth. However, they present early water and gas channeling but could be remediated by using foaming agents to control these phenomena through blocking channeling areas. In Mexico these reservoirs have pressure up to 5,500 psi, high temperature up to 200 °C, salinity up to 400,000 ppm, and hardness up to 250,000 ppm; due to these thermodynamic conditions, there has been no available technology to form stable enough foams. In this work, a foaming supramolecular surfactant with the capability to chelate Ca 2+ ions is examined. As a result, surfactant monomers are bridged by captured Ca 2+ cations leading to the formation of high-molecular-weight oligomers, which significantly increment the viscosity of the solution improving the foam stability, and since at this manner the Ca 2+ cations are no longer available to precipitate as components of solid salts, the foaming supramolecular surfactant also performs as antiscalant. These observations are explained through quantum theoretical modeling. The foam is stable, effectively blocking the gas channels, whereas in presence of oil the foam is broken leading the oil to pass into the wellbore. The characteristic rheological properties of the foam allow its injection into the formation at a range of flow rates, foam qualities, and shear stress to achieve the flooding and the blocking of a variety of fractured carbonate formations, and the change of the wettability of the matrix, which is a desirable behavior in a huff and puff process, as reported in a previous publication about a successful pilot test of this foam.

Naturally Fractured Carbonate Reservoir Characterization: A Case Study of a Mature High-Pour Point Oil Field in Hungary

An integrated technical study was conducted for a field development project in west Hungary. This study offers a better solution for estimating petrophysical properties and fracture facies vertically along the well and laterally for 3D static and dynamic models of naturally fractured reservoirs in carbonate rocks. More than 30 wells with 40 years of production history were used in order to build reliable static and dynamic models. The fracture class/facies plays an essential role in the spatial distribution of petrophysical properties during 3D reservoir modeling. It was defined by integrating conventional logs, image logs, drilling parameters, and production or well test data. Three fracture facies are defined as macrofracture (including permeable subseismic fault), microfracture, and host rock. Subsequently, the fracture class’s spatial distribution is guided by seismic attributes of fault likelihood combined with the geological concept of the fault and damage zone. As a result, the established fracture classes along the wells are validated by static and dynamic subsurface data. A spherical self-organizing map (SOM) was also implemented for predicting the open-fracture location in wells having limited subsurface data. Moreover, fracture lateral distribution follows the distribution of the fault zone of the fault core, high damage zone, low damage zone, and host rock. The higher the fault displacement, the wider the damage zone and fault core formed. Macrofractures and microfractures frequently appear around the fault core and high damage zone. While only microfractures are dominantly present in the low damage zones, in contrast, the unfractured class is dominantly distributed in the host-rock area. Also, the lithologies are considered in distributing the fracture class because the rock mechanic properties and the number of fractures are strongly controlled by rock compositions. Once the fracture class is distributed, porosity, permeability, and water saturation are modeled in the three-dimensional (3D) geocellular model. Finally, this fracture class also plays a role as a rock typing for reservoir simulation. The saturation height model is built using the fracture class distribution resulting in the initialization, history-matching process, and production forecast from 20 wells showing excellent quality. As a novelty, this study offers a better understanding of fracture distribution and accelerates the history-matching process with a more confident result of the production forecast. In the absence of advanced technologies, like image logs and production logging (PLT) measurements, this study still effectively assists us in recognizing the fracture presence and its quality in both well-depth interval and 3D spatial space, and successfully guided us in proposing new infill drilling with strong confidence and delivering on the high end of expected results.

Investigating the potential of microbial enhanced oil recovery in carbonate reservoirs using Bacillus persicus

In this study, several laboratory experiments were conducted to evaluate the performance of Bacillus persicus as a microbial enhanced oil recovery (MEOR) agent in conventional and fractured carbonate reservoirs. In these experiments, it was observed that using the microbial solution as an imbibing fluid can produce 12.5% of the original oil in place. Complementary imbibition experiments demonstrated that lower recoveries are achievable using Sodium Dodecyl Sulfate (SDS) surfactant and supernatant solutions. In order to investigate effective mechanisms, various experiments, including wettability alteration measurements, biosurfactant production tests, viscosity, and pH measurements, were performed. The contact angle tests exhibited that the selected microorganism can alter the wettability of carbonate surfaces by reducing the water/oil contact angle from 132° to 54°, representing a change from an oil-wet to water-wet state. Bacillus persicus also showed favorable results in biosurfactant production tests, including interfacial tension, emulsion index E24%, and oil displacement experiments. The viscosity measurements showed that the bacterial solution could decrease oil viscosity by about 27%. Moreover, no significant changes were found in the pH of the microbial solution during incubation and after treatment. Finally, core flooding experiments exhibited that microbial solution injection as a tertiary oil recovery method could recover 37.52% of the original oil in place. The results obtained in this study demonstrated the potential of MEOR plans targeting oil-wet/mixed-wet fractured and non-fractured carbonate reservoirs.

Application and Optimization for Network-Fracture Deep Acidizing Technique of Fractured Carbonate Reservoirs

Abstract The fractured carbonate rock reservoir is widespread in Sichuan Basin, and the characteristics of different areas are different. The development of natural fractures is varying degrees, lost circulations occur frequently, and the formation heterogeneity is strong, which causes the formation not sufficiently stimulated by acidizing. It may affect the effectiveness of reservoir stimulation. To advance the whole stimulation effect of the heterogeneous fractured carbonate reservoir, a new solution for determining the invasion radius during drilling in a fracture network reservoir is presented, which is based on solute transport and convection-diffusion equations. It can predict the invasion radius caused by mud loss and determines the range of mud loss invasion, which clarify the scope and degree of reservoir damage. The formation of skin factors polluted by mud loss was calculated. The experiments verified that the acidizing technology can remove reservoir damage and reduce the polluted formation of skin factors. The opening pressure of the nature fracture closed is calculated which can control the acidizing area. It is confirmed how many fractures in the carbonate reservoir can be opened under the wellhead pressure limit, which meets the construction conditions of acidizing fractured reservoirs. The framework of network-fracture deep acidizing technology was established, which can efficiently break through the detrimental zone caused by lost circulation, break down the natural fracture network, and decrease the formation of the skin. The restart pressure of natural fractures was calculated, and the design parameters such as pump pressure and displacement were optimized to quantify the scope of reservoir stimulation and the scale of acid fluid. The technique of network-fracture deep acidizing was applied for well A, the formation of skin after acidizing can be reduced to -4, and the testing production of well A was 58.87×104 m3/d. The technique of network-fracture deep acidizing can quantify the acid scale and sweep area in acid fracturing design, which develops the fracturing efficiency and improves the fracturing engineering.

Combining Knowledge and a Data Driven Method for Identifying the Gas Kick Type in a Fractured Formation

The main forms of gas kicks into the wellbore during drilling in fractured carbonate reservoirs are underbalanced pressure and gravity displacement. These two forms of gas kicks have different mechanisms of gas entry into the wellbore and different well control measures, which require the timely identification of the type of gas kick when it occurs. A two-phase flow model with a wellbore-formation coupling was developed, based on the gas kick rate models. The variation characteristics of the bottomhole gas influx rate, the wellbore free gas, the bottomhole pressure, the bottomhole pressure change rate, the pit gain and the outlet flow rate during an underbalanced pressure gas kick and a gravity displacement gas kick, were compared and analyzed. Combining the dynamic time warping (DTW) and the wellbore-formation, coupled with a two-phase flow model, an identification method of the gas kick type, based on the DTW was proposed. Following the detection of the gas kick, the identification is performed by calculating the DTW distance between the surface parameter time series, obtained from the two-phase flow simulation and the surface parameter time series, measured in real time. The field example results show that the method can identify the type of gas kick, based on the real-time surface measurement parameters and provide a basis for taking targeted well control measures.

Experimental Study on Alternating Injection of Silica and Zirconia Nanoparticles with Low Salinity Water and Surfactant into Fractured Carbonate Reservoirs for Enhanced Oil Recovery

Recently, the application of low salinity water (LSW), nanoparticles (NPs), and surfactants (collectively abbreviated as LNS) in carbonate formations for enhanced oil recovery (EOR) purposes has been under investigation, but relatively few studies have been performed for their implementation in fractured carbonate reservoirs (FCRs). The objective of this study is to apply the recently proposed method of alternatively injecting LNS in cycles into FCRs using silica and zirconia NPs. The cumulative oil recovered from the two coreflooding experiments performed at 3000 psi overburden pressure and 70 °C temperature is reported in this study in addition to spontaneous imbibition (SI) experiments. The experimental design is structured to depict the best industrial practice for the injected fluids in FCRs. Furthermore, this work investigates the effect of zirconia NPs on the interfacial tension (IFT) between the injected fluids and crude oil under the previously stated experimental conditions. The outcome of these experiments divulges that the alternating injection of LNS employing silica and zirconia NPs is effective and well suited for EOR applications in FCRs owing to a cumulative oil recovery of approximately 8 and 7% of the original oil in place (OOIP), respectively. This study validates the implementation of the recently proposed alternating injection of the LNS technique for FCRs and shows its performance utilizing newly acquired zirconia NPs, which is relevant for industrial application at a large scale.

Characteristics and application of present in situ stress field of a strike-slip fault: a 3D finite-element simulation study

AbstractPrevious hydrocarbon explorations in the middle of the Tarim Basin indicate that strike-slip faults play an important role in the development of Ordovician carbonate reservoirs and hydrocarbon accumulation. The SB5 fault in the Tarim Basin was the target of this investigation. An evaluation of the stress in situ was carried out and provided boundary conditions to build a 3D geomechanical model. The distribution and application of present in situ stress in the strike-slip fault were studied. The results show good agreement between the absolute measured stress in situ and the modelled stresses, revealing a different stress regime along the strike-slip fault. The uplift segment belongs to a strike-slip stress state, and other areas belong to a normal fault stress state. The strike-slip fault has a significant influence on the present in situ stress distribution. The direction of the maximum horizontal stress deflects near the fault and tends to be parallel to the fault strike. This work introduces a comprehensive evaluation of the present in situ stress of the fractured carbonate reservoirs controlled by the strike-slip fault system. The present in situ stress direction can clarify the propagation direction of hydraulic fracturing and serve to evaluate the effectiveness of natural fractures.

RETRACTED ARTICLE: Improvement of seismic data quality and recognition of fault discontinuities through seismic data conditioning applications: a case study of Issaran oil field, Gulf of Suez, Egypt

Obtaining high-quality seismic imaging in shallow heterogeneous carbonate reservoirs with complicated structural regimes, such as the Issaran field, is difficult. Issaran field is a heavy oil shallow heterogeneous fractured carbonate reservoirs located in the Gulf of Suez of Egypt. It has many geological factors that affect image quality and pose numerous challenges. In addition, the seismic data was acquired more than 12 years ago, with narrow azimuth and short offsets. As a result, the fault zones are not sharply defined. Furthermore, the seismic data was processed about 10 years ago. The signal-to-noise ratio is relatively poor due to the random and coherent noises. A robust data conditioning workflow for noise suppression and fault discontinuity sharpening is used to improve the post-stack seismic data quality. In this context, a steering dataset was generated, and a dip-steered median filter (DSMF), a dip-steered diffusion filter, and a fault enhancement filter (FEF) were applied to sharpen the discontinuities. Structural attributes were evaluated, to investigate how the newly applied data conditioning affects the clarity of fault patterns. Furthermore, multiple physical attributes were extracted, including instantaneous phase, instantaneous frequency, and RMS amplitude to better understand the reservoir stratigraphic heterogeneity. The application of DSMF is useful in removing the residual random noises. The FEF-similarity attribute revealed small-scale faults with a 50-foot vertical throw. The physical attributes proved that the Issaran carbonate facies is controlled by structure. Moreover, the RMS amplitude attribute helped in distinguishing between porous and non-porous dolomite facies. As imaging quality has significantly improved, the applied seismic data conditioning workflow is beneficial for the field development in Issaran field. It is also suggested that this data conditioning workflow be applied in other heterogeneous carbonate reservoirs with complex structures around the world.

Influence of Fracture Types on Oil Production in Naturally Fractured Reservoirs

Since more than half of the crude oil is deposited in naturally fractured reservoirs, more research has been focused on characterizing and understanding the fracture impact on their production performance. Naturally open fractures are interpreted from Fullbore Formation Micro-Imaging (FMI) logs. According to the fracture aperture, they are classified as major, medium, minor and hairy fractures in decreasing order of their respective aperture size. Different fracture types were set up in this work as a Discrete Fracture Network (DFN) in synthetic models and a sector model from a highly naturally fractured carbonate reservoir. The field sector model includes four wells containing image logs from two wells and production data from two other wells. Numerous simulations were conducted to capture the contribution of fracture type on production performance. Primary recovery was used for synthetic and field sector models, while waterflooding and gas injection scenarios were considered just for the synthetic models. The results showed that the fracture type and its extent play an essential role in production for all studied models. The reservoir production capabilities might be underestimated by ignoring any fracture types present in the reservoir, especially the major ones. In the secondary recovery, fractures had different impacts. Better displacement and higher recovery were promoted for waterflooding, whereas faster breakthrough times were observed for the gas injection. The performance during gas injection was more dependent on fracture permeability changes than waterflooding. This study’s findings can help in better understanding the impact of the different types of fracture networks on oil recovery at the various production stages. Additionally, the history matching process can be improved by including all types of fractures in the dynamic model. Any simplification of the fracture types might end in overestimating or underestimating the oil recovery.

A static modeling approach to the Brown Limestone carbonate reservoir, Geisum Oilfield, Gulf of Suez, Egypt

The Gulf of Suez in Egypt contains more than 80 conventional oil fields with reservoirs from Precambrian up to Quaternary age. To date, these fields have all been conventional resources. This abstract will take part of the Gulf of Suez sequence within the fields of Petrogulf Misr Company and present a work process for unconventional resource assessment of the Brown Limestone formation within one of these areas. The Brown Limestone formation is a Late Cretaceous Pre-rift mega sequence succession and plays an important role in the conventional system of Gulf of Suez, Brown Limestone formation is not only as one of the important source rocks, but also a fractured carbonate reservoir in multiple fields especially is the southern Geisum oil field. However, this formation is characterized by uncertainty due to the complexity of reservoir architecture, various lithologies, lateral facies variations, and heterogeneous reservoir quality. These reservoir challenges, in turn, affect the effectiveness of further exploitation of this reservoir along the Gulf of Suez Basin. In this work, we conduct an integrated study using multidisciplinary datasets and techniques to determine the precise structural, petrophysical, and facies characteristics of the Brown Limestone Formation and predict their complex geometry in 3D space. The Brown Limestone formation is considered to be as a reservoir in the study area. The value of water saturation ranges from 15 to 45%, where the value of Effective Porosity ranges from 11 to 15% for the selected potential intervals in Brown Limestone due to the highly structural setting in the study area, so Reservoir thickness was used as the proxy for reservoir effectiveness where thicker reservoir had a higher chance of containing multiple intervals for good potential intervals.

Seismic Anisotropic Fluid Identification in Fractured Carbonate Reservoirs

Seismic fluid identification plays an important role in reservoir exploration and development. Natural vertical fractures are common in carbonate rocks, it is essential to consider fracture-induced anisotropy in the fluid identification of fractured carbonate reservoirs. We have developed a novel Bayesian elastic impedance variation with an angle and azimuth (EIVAZ) inversion approach for directly estimating the fracture fluid indicator (FFI), which can avoid cumulative errors produced in the indirect calculation process. Under the assumption of weak anisotropy and a small incident angle, we first derive a new approximate PP-wave coefficient for horizontal transverse isotropic (HTI) media. Analysis shows that the new approximation has reasonable accuracy at angles of incidence less than 30°. To estimate the FFI from observed azimuthal P-wave seismic reflection data, we further deduce the azimuthal EI equation and establish a two-step inversion workflow. Finally, the proposed approach is demonstrated by tests on a synthetic data example and a field data set of a fractured carbonate reservoir in the Sichuan Basin (China). Results show that the model parameters can be reasonably estimated even with moderate noise levels. The estimated FFI and quasi-normal fracture weakness show relatively high values at the location of reservoirs, which reliably indicate a fractured gas-bearing reservoir.

Subsidence Rings and fracture pattern around dolines: Implications for fractured carbonate reservoirs

Subsidence Rings and fracture pattern around dolines: Implications for fractured carbonate reservoirs

Oil-gas two-phase seepage model in fractured carbonate reservoirs

Fractures are developed in fractured carbonate reservoirs. Traditional fracture characterization methods and seepage mathematical models cannot accurately describe the complex spatial distribution of large-scale fractures and their stress sensitivity, and do not consider the two-phase seepage of oil and gas, resulting in the dynamic analysis results have large errors. Aiming at this problem, a two-phase seepage model of oil and gas in fractured carbonate reservoirs considering stress sensitivity is established in this paper, and the semi-analytical solution of the model is obtained by using three-dimensional source function theory and finite difference method. The accuracy of the model is verified by comparison with commercial numerical simulation software, the production performance curve of oil and gas two-phase is drawn, and the influence of key seepage parameters of reservoirs and fractures on production performance is analyzed. The results show that the hybrid solution method of 3D source function and finite difference can realize the accurate and efficient solution of 3D discrete fracture oil and gas two-phase seepage model. The stress sensitivity effect leads to serious loss of fracture permeability and increase of fluid seepage resistance, which seriously affects the production of oil wells. The greater the fracture permeability, the higher the initial value of production, and the higher the position of the production curve. The longer fracture length, the higher the production curve in the early and middle production stages, and the slower the production decline.

The Effect of the Reservoir Characteristic Parameters on the SAGD Economic Feasibility in Fractured Carbonate Reservoirs

The Effect of the Reservoir Characteristic Parameters on the SAGD Economic Feasibility in Fractured Carbonate Reservoirs

The effect of mechanical stratigraphy on natural fractures morphology and distribution in carbonate reservoirs

High-resolution borehole images and other well logs are used to study the interrelationship between mechanical stratigraphy and natural fractures in the carbonates of the Dehram reservoirs in the Zagros area, Southwest of Iran. Natural fractures are characterized for their vertical distribution and morphology in six nearby anticlinal structures hosting one of the largest gas provinces in the world. Mechanical stratigraphy is evaluated using dipole sonic and density data from the same boreholes in these six gas fields. This study shows that the effect of mechanical stratigraphy on the fracture system in carbonate reservoirs can be evaluated in two scales. Large-scale mechanical stratigraphy, represented by rock strength variations within units with more than 1-m thickness, influences the overall fracture intensity. At the same time, the effect of small-scale mechanical stratigraphy is more pronounced on aperture and continuity as two elements of the morphology of natural fractures. This scale of rock mechanics is practically discernible using high-resolution borehole images. Both scales of mechanical stratigraphy were crucial when building predictive models of reservoir performance in naturally fractured carbonate reservoirs.

Gel-Forming and Plugging Performance Evaluation of Emulsion Polymer Crosslinking System in Fractured Carbonate Rock

The water channeling of fractured carbonate rock seriously affects oil recovery, and this problem is especially serious in the Kazakh North Troyes oilfield. A conventional powder polymer plugging system needs to be hydrated ahead of time, which increases the cost and difficulty of field operation and it cannot realize large-scale plugging operations. The new emulsion polymer crosslinked system can realize rapid hydration and real-time mixing, having low base liquid viscosity and good fluidity and injectability. The results of the laboratory study show that the gelling time of HR9806 emulsion polymer and organic chromium crosslinker was 6~8 h. 0.5 wt % HR9806, which is recommended for field use with P/C ranging from 2.5 to 5.0. The emulsion polymer crosslinking system was found to be highly adaptable in reservoirs and had salinity resistance. Mineral salt and reservoir core were able to enhance the gel strength of the system but shortened the gelling time of the system by about 2 h. The gel (HR9806) had good shear resistance. It still had a viscosity of 220 mPa·s under high-speed shearing (Temperature = 54 °C), and the formed gel system shear resistance increased with increasing concentration. The emulsion system of “0.50 wt % HR9806 emulsion polymer + 0.15 wt % organic chromium crosslinker + brine” had a strong plugging effect in the fractured core and sand-filled pipe model, with residual resistance coefficient ≥30, effective plugging rate ≥ 95.0%, and oil–water selectivity of 0.45. In this paper, the levels of weak gel strength were used, providing an experimental and theoretical reference for improving the application effect of the weak gel system in the field. The study found that the weak gel system can better enter the fractured carbonate reservoir and form a plugging effect in the fracture, improving the effect of subsequent water flooding matrix oil recovery.