Identification of Micro Fractures in Cretaceous Bioclastic Limestone in Iraq and Its Influence on Development of Reservoirs

2021 ◽  
Author(s):  
Genjiu Wang ◽  
Dandan Hu ◽  
Qianyao Li
Keyword(s):  
Water Movement ◽  
Rock Fracture ◽  
Water Injection ◽  
Three Dimensional ◽  
Carbonate Reservoir ◽  
Distribution Data ◽  
Fracture Development ◽  
Reservoir Conditions ◽  
Data Volume ◽  
Southern Iraq

Abstract It is generally believed that Cretaceous bioclastic limestone in Mesopotamia basin in central and southern Iraq is a typical porous reservoir with weak fracture development. Therefore, previous studies on the fracture of this kind of reservoir are rare. As a common seepage channel in carbonate rock, fracture has an important influence on single well productivity and waterflooding development of carbonate reservoir. Based on seismic, core and production data, this study analyzes the development characteristics of fractures from various aspects, and discusses the influence of fractures on water injection development of reservoirs. Through special processing of seismic data, it is found that there are a lot of micro fractures in Cretaceous bioclastic limestone reservoir. Most of these micro fractures are filled fractures without conductivity under the original reservoir conditions. However, with the further development of the reservoir, the reservoir pressure, oil-water movement, water injection and other conditions have changed, resulting in the original reservoir conditions of micro fractures with conductivity. The water cut of many production wells in the high part of reservoir rises sharply. In order to describe the three-dimensional spatial distribution of fractures, the core data is used to verify the seismic fracture distribution data volume. After the verification effect is satisfied, the three-dimensional fracture data volume is transformed into the geological model to establish the permeability field including fracture characteristics. The results of numerical simulation show that water mainly flows into the reservoir through high angle micro fractures. Fractures are identified by seismic and fracture model is established to effectively recognize the influence of micro fractures on water injection development in reservoir development process, which provides important guidance for oilfield development of Cretaceous bioclastic limestone reservoir in the central and southern Iraq fields.

PVT and Pressure Analysis in Third pay Reservoir of Zubair Oilfield Southern Iraq

2020 ◽  
Vol 27 (2) ◽  
pp. 55-59
Author(s):  
Karrar K. Abdulwahhab ◽  
Mohammed S. Al-Jawad
Keyword(s):  
Pressure Drop ◽  
Water Injection ◽  
Reservoir Pressure ◽  
Gas Oil ◽  
Pvt Data ◽  
Reservoir Conditions ◽  
Point Pressure ◽  
Strong Depletion ◽  
Southern Iraq ◽  
Pressure Analysis

In this paper the pressure drop and PVT data that used in the model to describe the behavior ofreservoir fluids of 3rd pay reservoir of Zubair field is explained. The wells in Hammar-Shuaiba area showhigh Gas Oil Ratio, exceeding 1,000 scf/stb. This is bad sign and that mean reservoir pressure is reducedramatically and gas will produced , finally the energy that use to push the oil from reservoir to thesurface will decrease. Eleven samples have been collected and analyzed from all 3rd pay reservoirs overthe years, seven samples in Hammar –Shuaiba area. The PVT data resulted to be scattered, being notpossible to define any acceptable conclusion about their trend versus depths, taking also into account thatthey are not referred to the same temperature. The main difference between the old and new PVT is theBubble Point pressure at reservoir conditions, which increases from 2646 psi to 2760 psi. Historicalpressure behavior shows that water Injection is beneficial to maintain stable pressure trend. Pressureanalysis shows a strong depletion start from 2013 in various zones of Hammar Shuaiba domes.

Porosity and Permeability Alteration of Carbonates by CO2-Enriched Brine Injection

2019 ◽  
Vol 965 ◽  
pp. 107-115 ◽  
Author(s):  
Diana Maria Hernandez Castro ◽  
Janeth Alina Vidal Vargas ◽  
Erika Tomie Koroishi ◽  
Luis Fernando Lamas de Oliveira ◽  
Osvair Vidal Trevisan
Keyword(s):  
Water Injection ◽  
Carbonate Reservoir ◽  
Operational Conditions ◽  
Pressure Transducers ◽  
The Core ◽  
Precipitation Decrease ◽  
Reservoir Conditions ◽  
In Series ◽  
Carbonated Water Injection ◽  
Carbonated Water

Some carbonate reservoirs are known for their high CO2 content in oil. One possibility to handle this gas without environmental problems is to reinject it into the reservoir. Injection of carbonated water has been drawing attention because it is an advantageous technique when compared to gaseous CO2 injection, due to its improvement in mobility in the reservoir. The objective of this study is to evaluate the phenomenon of dissolution and precipitation during carbonated water injection in carbonate rocks. These effects are identified by analyzing the porosity variations through X-ray computer tomography images and permeability profile, determined indirectly by pressure transducers that measured the differential pressure by the fluid at the inlet and outlet of the core holders. The Coreflooding test were carried out with two core holders in series to represent a near region at the reservoir by the injection of brine saturated with 25% of CO2 in reservoir samples, composed of dolomite, calcite and clay. The test were performed using the following reservoir conditions of 8,500 psi at 70°C. Based on the experimental data provided by CT images, it can be seen that the core porosity increases or decrease during carbonated water injection due to coexistence of dissolution (increase of porosity) and precipitation (decrease of porosity) along the samples. These phenomena are observed in regions with high heterogeneity in porosity. In addition, the mineralogy of the cores is composed by three minerals, which influence in the capacity of reaction with carbonated water. For the experiment, the core placed in the core holder one presented a porosity increase and the second one decreased. On the other hand, the permeability showed a significant increase for both cores, it is believed that, the injection promoted a preferential way flow (wormhole) that affected considerably the permeability of the rock. The novelty of the investigation is that the experiments were carried out using Brazilian pre-salt carbonate reservoir rocks with mineralogy composed basically by dolomite, calcite and clay. Also, experimental work was performed at reservoir operational conditions.

scholarly journals Injection-production optimization of carbonate reservoir based on an inter-well connectivity model

2021 ◽  
pp. 014459872199465
Author(s):  
Yuhui Zhou ◽  
Sheng Lei ◽  
Xuebiao Du ◽  
Shichang Ju ◽  
Wei Li
Keyword(s):  
History Matching ◽  
Water Injection ◽  
Field Application ◽  
Carbonate Reservoir ◽  
Production Optimization ◽  
Oil Field ◽  
Carbonate Reservoirs ◽  
Utilization Rate ◽  
Production Volume ◽  
Connectivity Model

Carbonate reservoirs are highly heterogeneous. During waterflooding stage, the channeling phenomenon of displacing fluid in high-permeability layers easily leads to early water breakthrough and high water-cut with low recovery rate. To quantitatively characterize the inter-well connectivity parameters (including conductivity and connected volume), we developed an inter-well connectivity model based on the principle of inter-well connectivity and the geological data and development performance of carbonate reservoirs. Thus, the planar water injection allocation factors and water injection utilization rate of different layers can be obtained. In addition, when the proposed model is integrated with automatic history matching method and production optimization algorithm, the real-time oil and water production can be optimized and predicted. Field application demonstrates that adjusting injection parameters based on the model outputs results in a 1.5% increase in annual oil production, which offers significant guidance for the efficient development of similar oil reservoirs. In this study, the connectivity method was applied to multi-layer real reservoirs for the first time, and the injection and production volume of injection-production wells were repeatedly updated based on multiple iterations of water injection efficiency. The correctness of the method was verified by conceptual calculations and then applied to real reservoirs. So that the oil field can increase production in a short time, and has good application value.

Injectivity and Propagation of Sulfonated Acrylamide-Based Copolymers in Low Permeability Carbonate Reservoir Cores in Harsh Salinity and Temperature Conditions : Challenges and Learnings from a Middle East Onshore Case Study

2021 ◽  
Author(s):  
Nicolas Gaillard ◽  
Matthieu Olivaud ◽  
Alain Zaitoun ◽  
Mahmoud Ould-Metidji ◽  
Guillaume Dupuis ◽  
...  
Keyword(s):  
Middle East ◽  
Polymer Solutions ◽  
Carbonate Reservoir ◽  
Core Material ◽  
Low Permeability ◽  
The Core ◽  
Reservoir Conditions ◽  
Carbonate Cores ◽  
The Impact ◽  
Mobility Reduction

Abstract Polymer flooding is one of the most mature EOR technology applied successfully in a broad range of reservoir conditions. The last developments made in polymer chemistries allowed pushing the boundaries of applicability towards higher temperature and salinity carbonate reservoirs. Specifically designed sulfonated acrylamide-based copolymers (SPAM) have been proven to be stable for more than one year at 120°C and are the best candidates to comply with Middle East carbonate reservoir conditions. Numerous studies have shown good injectivity and propagation properties of SPAM in carbonate cores with permeabilities ranging from 70 to 150 mD in presence of oil. This study aims at providing new insights on the propagation of SPAM in carbonate reservoir cores having permeabilities ranging between 10 and 40 mD. Polymer screening was performed in the conditions of ADNOC onshore carbonate reservoir using a 260 g/L TDS synthetic formation brine together with oil and core material from the reservoir. All the experiments were performed at residual oil saturation (Sor). The experimental approach aimed at reproducing the transport of the polymer entering the reservoir from the sand face up to a certain depth. Three reservoir coreflood experiments were performed in series at increasing temperatures and decreasing rates to mimic the progression of the polymer in the reservoir with a radial velocity profile. A polymer solution at 2000 ppm was injected in the first core at 100 mL/h and 40°C. Effluents were collected and injected in the second core at 20 mL/h and 70°C. Effluents were collected again and injected in the third core at 4 mL/h and 120°C. A further innovative approach using reservoir minicores (6 mm length disks) was also implemented to screen the impact of different parameters such as Sor, molecular weight and prefiltration step on the injectivity of the polymer solutions. According to minicores data, shearing of the polymer should help to ensure good propagation and avoid pressure build-up at the core inlet. This result was confirmed through an injection in a larger core at Sor and at 120°C. When comparing the injection of sheared and unsheared polymer at the same concentration, core inlet impairment was suppressed with the sheared polymer and the same range of mobility reduction (Rm) was achieved in the internal section of the core although viscosity was lower for the sheared polymer. Such result indicates that shearing is an efficient way to improve injectivity while maximizing the mobility reduction by suppressing the loss of product by filtration/retention at the core inlet. This paper gives new insights concerning SPAM rheology in low permeability carbonate cores. Additionally, it provides an innovative and easier approach for screening polymer solutions to anticipate their propagation in more advanced coreflooding experiments.

scholarly journals Research on Microscopic Evolution Laws of Sandstone Deformation and Failure Based on the Particle Discrete Element Method

2021 ◽  
Vol 2021 ◽  
pp. 1-12
Author(s):  
Zhiwei Cai ◽  
Tongqing Wu ◽  
Jian Lu ◽  
Yue Wu ◽  
Nianchun Xu
Keyword(s):  
Shear Crack ◽  
Rock Fracture ◽  
Confining Pressure ◽  
Particle Flow Code ◽  
Shear Cracks ◽  
Deformation And Failure ◽  
Fracture Development ◽  
Confining Pressures ◽  
The Law ◽  
Microcrack Growth

The fracture of sandstone is closely related to the condition of internal microcracks and the fabric of micrograin. The macroscopic mechanical property depends on its microscopic structures. However, it is difficult to obtain the law of the microcrack growth under loading by experiments. A series of microscopic sandstone models were established with particle flow code 3D (PFC3D) and based on the triaxial experiment results on sandstones. The experimental and numerical simulations of natural and saturated sandstones under different confining pressures were implemented. We analyzed the evolution of rock deformation and the rock fracture development from a microscopic view. Results show that although the sandstones are under different confining pressures, the law of microcrack growth is the same. That is, the number of the microcracks increases slowly in the initial stage and then increases exponentially. The number of shear cracks is more than the tensile cracks, and the proportion of the shear cracks increases with the increase of confining pressure. The cracking strength of natural and saturated sandstones is 26% and 27% of the peak strength, respectively. Under low confining pressure, the total number of cracks in the saturated sample is 20% more than that of the natural sample and the strongly scattered chain is barely seen. With the increase of the confining pressure, the effect of water on the total number of cracks is reduced and the distribution of the strong chain is even more uniform. In other words, it is the confining pressure that mainly affects the distribution of the force chain, irrespective of the state of the rock, natural or saturated. The research results reveal that the control mechanism of shear crack friction under the different stress states of a rock slope in the reservoir area provides a basis for evaluating the stability of rock mass and predicting the occurrence of geological disasters.

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