Carbonate rocks are complex in their structures and pore geometries and often exhibit a challenge in their classification and behavior. Many rock properties remain unexplained and uncertain because of improper characterization and lack of data QC. The main objective of this paper is to study flow behavior of relative permeability with different rock types in complex carbonate reservoirs.
Representative core samples were selected from two major hydrocarbon reservoirs in Abu Dhabi. Rock types were identified based on textural facies, PoroPerm characteristics and capillary pressure. Porosity ranged from 15% to 25%, while permeability varied from 1 mD to 50 mD. Primary drainage and imbibition water-oil relative permeability (Kr) curves were measured by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. High-rate bump floods were designed at the end of the flooding cycles to counter capillary end effects. Aging period of 4 weeks was incorporated at the end of the drainage cycle. Robust data QC was performed on the samples, and final validation of the relative permeability was conducted by numerical simulation of the raw data and measured capillary pressure.
The followed QC procedure was crucial to eliminate artefact in the relative permeability curves for proper data evaluation. The different rock types showed consistent variations in the relative permeability hysteresis and end points. Imbibition relative permeability curves showed large variations within the different rock types, where Corey exponent to oil ‘no’ increased with permeability from 3 to 5, whereas the Corey exponent to water ‘nw’ decreased with permeability and ranged from 3 to 1.5. The variations in the relative permeability curves are argued to be the result of different rock structures and pore geometries. Variations were also seen in the end-point data and showed consistent behavior with the rock types.
The different carbonate rock types were identified based on geological and petrophysical properties. Higher permeability samples were grain-dominated and more heterogeneous in comparison to the lower permeability samples, which were mud-dominated rock types. Imbibition Kr curves showed larger variations than the primary drainage data, which cannot be interpreted based on wettability considerations only. The relative permeability curves have been thoroughly evaluated and QC'd based on raw data of pressure and saturation by use of numerical simulation. Such RRT-based Kr data are not abundant in the literature, and hence should serve as an important piece of information in mixed-wet carbonate reservoirs.
Syofyan, Syofvas (ADNOC Onshore) | Latief, Agus Izudin (ADNOC Onshore) | Ahmed Al Amoudi, Mohsen (ADNOC Onshore) | Al-Shamsi, Saif (ADNOC Onshore) | Hassan Ali Bal Baheeth, Asma (ADNOC Onshore) | Nestyagin, Andrey (ADNOC Onshore) | Ali Al-Shabibi, Tariq (ADNOC Onshore) | Banihammad, Basma (ADNOC Onshore) | Dasgupta, Suvodip (Schlumberger) | Mosse, Laurent (Schlumberger) | Yaseen Albuali, Abdulla (Schlumberger)
Carbonate reservoirs introduce challenge in providing accurate water saturation from conventional Archie equation. One of the reasons is due to the variability of the Archie cementation factor "m" because of complex and tortuous nature of these heterogeneous carbonates.
The study was performed by integrating core and log data from advance measurements to understand the root cause and range of the variability and an attempt to link sedimentology and diagenetic facies to petrophysical groups.
The Study focused on a carbonate reservoir with complex pore network. The formation resistivity factor (FRF) measurements were conducted with high-resolution sampling on a selected well. Each of FRF plug has associated porosity, permeability, thin sections, MICP, NMR and high-resolution dual energy micro CT scan. The m value from FRF is then plotted along the porosity-permeability plot. The capillary pressure parameters (entry pressure, slope, inflexion points) were extracted from MICP and relationship is plotted against m. Diagenetic facies described from the thin sections is compared versus m.
Principal component analyses was conducted to identify factors relating to m. The uncertainty on water saturation associated to variable parameter m was assessed using Monte Carlo analysis on multiple wells.
An advanced multi-frequency dielectric logging tool was run on couple of wells to provide variable water-phase tortuosity (MN) measurement. Specific analysis was performed to extract the variable m value from the measurement over limited zones, which has been derived from core "m" measurements.
Several wells located on the flank of the reservoir below water level were evaluated. Dean stark measurements were performed on a well and used to validate the saturation calculation.
It is obvious that the evaluated reservoir has high degree of heterogeneity as indicated by complex pore network with multi modal pore system as shown by the thin sections, MICP and plug CT Scan.
Sun, Zheng (China University of Petroleum at Beijing, Texas A&M University) | Shi, Juntai (China University of Petroleum at Beijing) | Yang, Zhaopeng (RIPED, CNPC) | Wang, Cai (RIPED, CNPC) | Gou, Tuobin (Lukeqin Oil Production Plant of Tuha Oilfield Company, PetroChina) | He, Minxia (China University of Petroleum at Beijing) | Zhao, Wen (China University of Petroleum at Beijing) | Yao, Tianfu (China University of Petroleum at Beijing) | Wu, Jiayi (China University of Petroleum at Beijing) | Li, Xiangfang (China University of Petroleum at Beijing)
Much attention has been attracted by the successful development of shale gas reservoir in recent decades. Correspondingly, research aspects of shale gas reservoirs become more and more heat among the academic community, especially in the fields of nanoscale gas transport mechanisms as well as the storage modes. Fascinated by the craft interactions exerted by organic or inorganic shale surface, drastic discrepancy takes place in terms of the gas behavior inside the nanoscale dimension and that in conventional dimension. It is crucial to figure out the exact influence on shale gas recovery and overall production efficiency due to the above large difference. Notably, this paper is designed to comprehensively explore the methane storage behavior in shale nanopores, expecting to provide the direct relationship between adsorption gas and free gas content under various environmental conditions. Also, a novel and simple prediction method with regard to ultimate gas recovery is proposed, which is connected to the pore size distribution and formation pressure. First of all, the gas storage modes in a single nanopore with defined pore size are analyzed seriously. As a result, the evaluation model is constructed for adsorption gas and free gas content in a single nanopore. After that, an upscaling method is applied to extend the adaptiability of the model from single nanopore to nanoporous modia. Finally, sensitivity factor analysis work is performed and a recovery prediction methodology is developed. Results suggest that the adsorption gas content will be a larger contribution to total gas content when it comes to small pore radius and low formation pressure. In contrast, free gas content will increase with the increasing pressure and pore size. More importantly, pore size distribution characteristic has a key impact on gas storage modes and ultimate gas recovery. The high proportion of small nanopores plays a detrimental role on gas recovery, resulting in large content of adsorption gas at low pressure, which will not be produced and remain in shale gas reservoirs.
Machine learning has attracted the attention of geoscientists over the years. In particular, image analysis via machine learning has promise for application to exploration and production technologies. Demands have grown for the automation of carbonate lithology identification to shorten the delivery time of work and to enable unspecialized engineers to conduct it. The image analysis of carbonate thin sections is time consuming and requires expert knowledge of carbonate sedimentology. In this study, the authors propose an image analysis technique based on deep neural network for carbonate lithology identification of a thin section, which is an important image analysis process required for oil and gas exploration. In addition, the authors consider that porosity and permeability variations in the same facies are controlled by the grain, cement, pore, and limemud contents. If the contents are accurately measured, the porosity and permeability can be determined more accurately than by using traditional methods such as point counting. The elucidation of the complex relation of porosity and permeability is the objective of automation of carbonate lithology identification. To perform image analysis of the thin section, the authors prepared a data set mainly comprising pictures of the Pleistocene Ryukyu Group, which were composed of reef complex deposits distributed in southern Japan. The data set contains 306 thin section pictures and annotation data labeled by a carbonate sedimentologist. The rock components was divided into four types (grain, cement, pore, and limemud). A convolution neural network (CNN) was utilized to train the model. After training the neural network, each of the four categories was interpreted by the trained model automatically. Resultantly, the accuracy of automatic Dunham classification was 90.6% and the mean average test accuracy of category identification was 83.9%. The interpretation seems highly consistent between human vision and machine vision in both the overview and pixelwise scales. This result indicates that it has sufficient potential to assist geologists and become a basic tool for practical applications. However, the accuracy of category identification is still insufficient. The authors believe that the model requires higher quality supervised data and a greater number of supervised data.
Carbonate reservoir rocks of the Najmah formation in Kuwait, with low porosity and low permeability, have been characterized using integrated digital and physical rock analyses methods. High-resolution imaging and analyses determined the microstructural characters of mineral matrix, organic matter (OM) distribution, organic and inorganic pore types, size distribution, and permeability variation within this kerogen-rich Late Jurassic stratigraphic unit.
Considerable heterogeneity of porosity and permeability was observed in the 100-ft studied interval of the Najmah Formation. Two-dimensional scanning electron microscopy (2D-SEM) imaging and three-dimensional focused ion beam SEM (3D-FIB-SEM) imaging highlighted the different types of porosities present within the formation rock. At each depth, several 2D-SEM images were used for characterization and selection of representative locations for extracting 3D FIB-SEM volumes. The 3D volumes were digitally analyzed and volumetric percentages of OM and total porosity were determined. The porosity was further analyzed and quantified as connected, nonconnected, and associated with organic matter. Connected porosity was used to compute absolute permeability in the horizontal and vertical directions in the area of interest.
Porosity associated with OM is an indicator of OM maturity and flow potential. It has been categorized as pendular type, spongy large grain, spongy small grain, fracture porosity within the OM, grain boundary fractures and intergranular porosity covering the entire OM. Permeability is not only influenced by porosity within OM or even apparent transformation ratio (ATR), it is also dependent on pore connectivity, pore sizes, and heterogeneity (e.g., high-permeability streaks). For high porosity samples, almost all pores are connected and contributing to permeability. For low porosity samples with high permeability, the flow is mainly through microfractures. It is possible that intergranular clay pores in highly thermally mature rocks were originally filled with OM and that, during progressive thermal maturation, transformation of OM to hydrocarbon(s) removed much of the pore filling OM.
It has also been observed that, although the total organic carbon (TOC) content of the rocks is significant (up to 18 wt%), and good maturity index (VR0>1), only few examined samples show good connected porosity within the OM. It is essential to evaluate the porosity within the OM thorough high-resolution measurements for pinpointing the prospective layers for future stimulated horizontal wells in this organic-rich source unit. These intervals can be considered as the potential sweet spots after integration with detailed petrophysics and geomechanical parameters for optimized well planning and completion design.
Yuan, Shuai (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Liang, Tianbo (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Zhou, Fujian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Liang, Xingyuan (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Yu, Fuwei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Li, Junjian (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing)
Replacing oil from small pores of tight rocks relies on altering the rock wettability with the injected fracturing fluid. Among different types of wettability-alteration surfactants, liquid nanofluid (LNF) has less adsorption loss during transport in the porous media and can efficiently alter the rock wettability; both make LNF a promising candidate to enhance oil recovery from tight reservoirs. In this study, a 2.5-D visualized micromodel with micro-sized pore throats is applied to elucidate the impacts of wettability alteration and spontaneous imbibition on oil-water flow in the porous media. Results provide direct evidence that the concentration of LNF changes wettability alteration rate and interfacial tension, and thus influencing the displacing rate of water into the originally oil-wet pores. This helps to optimize LNF usage in the fracturing fluid for enhanced oil recovery from tight rocks.
Noufal, Abdelwahab (ADNOC Upstream) | El Wazir, Zinhom (ADNOC Onshore) | Al Madani, Noura (ADNOC Onshore) | Shinde, Ashok (Baker Hughes, a GE company) | Perumalla, Satya (Baker Hughes, a GE company) | Aldin, Munir (MetaRock) | Govindrajan, Sudarshan (MetaRock) | Gokaraju, Deepak (MetaRock)
Heterogeneous nature of the Cretaceous carbonate reservoirs in Abu Dhabi increases there complexity to attain efficient characterization and hence development. During depletion, reservoir pressure reduction results in unequal increase of vertical and horizontal effective stresses and thus an overall increase in the effective mean and shear stresses on the reservoir pore structure. At reservoir pressures below a critical value (obtained via laboratory testing or post failure field analysis), the reservoir compacts at accelerated rates. Compaction and its associated reduction in reservoir pore volume leads to rapid loss in permeability, generation of fines and wellbore stability issues (e.g., casing collapse). Assessing the magnitude of these changes require laboratory measurements of rock compressibility (grain, bulk and pore compressibilities), and concurrent evaluations of reduction of pore volume, porosity and permeability as a function of reservoir pressure needs to be appropriately simulated in-situ stress conditions. Poor appreciation of the rock compressibility mechanics and its robust dependence on stress path (e.g., hydrostatic- and/or uniaxial strain compression) in addition to depletion rate may result in substantial cost.
The core intervals are selected to capture the lateral and vertical heterogeneity encountered in the studied reservoirs. The test program was designed to create a material model to capture the rock response to potential reservoir pressure changes. Single Stage Triaxial tests at multiple confining stresses were conducted to judge the shear failure. Tests recommended for evaluation and assessment of reservoir compaction are Uniaxial-strain compression (far-field compaction), triaxial compression (near wellbore), Hydrostatic (define the compaction cap) and constant stress-path. Additional tests were carried to characterize the poro-elastic response of reservoir rock and the stress-dependent permeability.
A combined failure envelope (defining shear (dilatant) and compaction ("Cap") for compactable sediments) of the rock was generated by integrating the results from Single stage Triaxial tests (Shear failure envelope), hydrostatic compression tests and UPVC tests (Compaction failure envelope). For field applications, it is useful to provide a visualization of the pre-production-state in-situ stress conditions, and the possible stress path trajectories of the reservoir, as a function of reservoir depletion. Such a failure envelope was generated for all the different lithofacies encountered across the field. The characterized material model enables us to assess and predict the risk of shear/compaction deformation associated with the reservoir pressure changes (considering field stress path). Using this display, the level of depletion resulting in accelerated compaction can be identified through laboratory testing.
The introduced workflow presents a comprehensive geomechanical characterization program for such complex carbonate reservoir. This utilizes a systematic approach to generate field wide understanding of rock response to depletion and injection. It can also act as a guide to address the compaction-based challenges faced in other reservoirs of Abu Dhabi.
One of the major problems in drilling industry that increases non-productive time, expenditures and environmental damages is Lost Circulation problem of drilling fluids. Lost Circulation in formations in low pressure or unconsolidated formations can be prevented with applying appropriate wellbore strengthening materials (WSM) which mitigate formation damages and provide with having a high production index after drilling operation. In this paper, designing of wellbore strengthening materials with different mechanisms are discussed and investigated.
Considering comprehensive study on different bridging mechanisms, resilient/deformable materials, organic fibers, and also investigation on optimizing particle size distribution of WSMs, two engineered solutions were designed and evaluated using Loss Circulation Material (LCM) Tester Equipment which has a cylinder structure, also pressure valve is set up on the upper cap and a tailor-made sand bed or slotted disk is fitted on its bottom. Different type of oil-based and water-based drilling fluids with and without designed WSMs were poured into the LCM Tester equipment, then 650-psi pressure was applied for 30 minutes. For each fluid, the invasion depth and invasion rate of the fluid into the sand bed was reported, also rheological properties and API Fluid loss were measured.
According to the results, invasion depth and invasion rate of fluids containing designed WSMs is magnificently lower in comparison with drilling fluids which not contained any WSMs. Drilling fluids contained the designed WSMs are highly-effective in both reservoir and non-reservoir formations for stabilizing the wellbore and preventing seepage loss in sandstones and mini-fractured formations. Evaluation of rheological properties and API-Fluid loss (before and after hot-rolling in 250° Fahrenheit for 2 hours) and comparing them with blank samples confirmed that designed WSMs did not have major adverse effect on rheological and fluid loss parameters. Designed WSMs in this paper can hold pressures as high as 650 psi in LCM tester equipment on (sand bed with permeability up to 5 Darcies) or slotted filter disks (up to 200-micron fracture width). Last but not least, regarding wellbore strengthening mechanisms, one of the WSMs includes dual bridging mechanisms in sandstone formations and the latter includes forming a stress cage in the wellbore surface that causes to decreasing permeability of the formations while drilling due to expansion of its designed resilient materials in the fractures.
Main goal of this research is using environmentally-friendly and economic waste materials to design highly effective WSMs. One of the designed WSMs includes environmentally-friendly organic waste fibers as a higher concentration additive. Additionally, one of the designed WSMs is more than 80% acid-soluble in 15% hydrochloric acid and the other one will be detached and left the wellbore pore-throats with beginning of production without any damage to reservoir zones.
We investigated the method of estimating porosity/permeability using X-ray CT, a non-destructive method. Using X-ray CT, a method of estimating the porosity/permeability is particularly developed in sandstone. However, for the carbonate rocks, the internal structure is complicated due to biological origin. This is difficult to recognize the pore space, therefore a method of estimating the porosity/permeability using X-ray CT has not been studied. This study is based on
Based on the 3D modeling of the X-ray CT, two rudist families (Radiolitidae and Ichthyosarcolites) were identified through their morphological characteristics such as inner diameter and shell thickness. A porosity of slab core around 50 feet is about 18% from CCA (Conventional Core Analysis). This slab core is made up of small rudist populations (length and wide size is 15-10mm), inside core confirmed 3D modeling (surface rendering and volume rendering), and calculated porosity is 0.89% from RCM (Reverse Coupling method). It is understood that this difference is dependent on matrix porosity and further investigation in the future is required in order to measure matrix porosity using thin section and micro X-ray CT. With regards to reservoir properties, the porosity is higher in the lower part than the upper part in the core interval. The size of the Radiolitidae could be dependent on the environment and its vertical variation suggests the change of depositional environment. Larger Radiolitidae, which appeared from 80 to 200 feet below the C-T (Cenomanian-Turonian) boundary, suggests a relatively strong wave influence. From a sedimentological point of view, the coarser matrix grain size supports the interpretation of depositional setting. On the other hand, from 30 to 80 feet below C-T boundary, smaller Radiolitidae is dominated. It was assumed that small Radiolitidae could be due to high physical stress under a restricted environment.
This study shows the advantage of X-ray CT image in rudist recognition, based on interpretation of depositional environment and understanding the reservoir property. The result of this study suggests the strong correlation between porosity/permeability and depositional environment (accommodation space) inferred from rudist fossil.
Singh, Maniesh (ADNOC Onshore) | Dey, Swapan Kumar (ADNOC Onshore) | Farooq, Umer (ADNOC Onshore) | Radwan, El Sayed (ADNOC Onshore) | Rajwade, Sachin (Weatherford Laboratories) | Tombokan, Xenia (Weatherford Laboratories) | Mendoza, Rafael (Weatherford Laboratories) | Hannon, Loay (Weatherford Laboratories) | Watson, Rayvan (Weatherford Laboratories)
The estimation of bulk volume of irreducible water (BVI) is one of the earliest and the most widely used applications of NMR logging using either a fixed T2 cutoff value or Spectral BVI. NMR BVI assumes that bound fluid resides in small pores and producible free fluids (FFI) resides in large pores where the pore throat and pore body sizes are often related. As T2 distribution is related to a pore body size, a T2 cutoff can partition BVI & FFI.
In Carbonates there is no clear relationship of pore throat size to pore body size, thus measuring BVI T2 cutoff per rock type becames important although challenging. This paper covers the importance of following correct laboratory procedures, quality assurance of laboratory experimential data, and innovative methods to determine reliable T2 cutoff which otherwise are very low and not practical to apply in the NMR log domain.
NMR analysis was performed with a 2 MHz field instrument using a CPMG sequence and sufficient echo trains to acquire reliable T2 distribution. T2 cutoff was determined on core samples with a wide range of porosity, permeability, and rock types. Core samples were analyzed for T2 distribution at elevated temperature and pressure. First the cores were saturated with formation brine to 100% Sw, followed by desaturation using the porous plate pressure equilibrium method to Swirr. Initially, desaturation with gas provided very low T2 cutoffs; desaturation steps were repeated using a lab oil with reservoir property to investigate its positive impact on the T2 cutoffs and to use in the NMR log domain.
The T2 curve of the fully saturated plugs with brine shows a shift towards the shorter T2 time. Determination of T2 cutoff from the gas-brine system in the laboratory results in lower T2 cutoff values approximately 15 to 50 msec. This is due to the lower T2 response at the Swirr state from the combined affect of pores still partially saturated with brine and gas diffusivity affects. When desaturating with lab oil, the NMR response results in more reliable T2 cut-off of 55 to 100 msec.
NMR T2 cutoff for BVI using the oil-brine system has been determined using two methods, a conventional method where T2 cutoff is determined where the cumulative T2 value of the Sw at 100% brine equals the cumulative T2 value of the Swirr. The other method is where the T2 cutoff separates major peaks of bound and free fluid in the incremental T2 response. The conventional method posed a challenge in picking correct T2 cutoff due to various complexity as outlined in the paper. The latter method provided more reliable and better control on picking T2 cutoff to apply in the NMR log domain.