Low Permeability Carbonate Reservoirs Research Articles

Experimental evaluations of nano high-viscosity friction reducers to improve acid fracturing efficiency in low-permeability carbonate reservoirs

A suitable pad fluid system creates a fracture surface with heterogeneous etching, reducing oil and gas flow resistance and improving the acid fracturing efficiency. The superior viscosity and friction reduction characteristics of a high-viscosity friction reducer have gradually replaced conventional slickwater and guar gum fracturing fluid. This study introduces nanoemulsions into a high-viscosity friction reducer, forming a nano high-viscosity friction reducer system resistant to acids and salts. Including nanoemulsions improves its viscosity, friction reduction rate, and imbibition oil recovery. Experimental results show that hydrophilic groups in nanoemulsions form hydrogen bonds with those in the high-viscosity friction reducer, increasing its viscosity by about 10% and enhancing its friction reduction performance by approximately 1.08 times under high flow rates. After breaking a gel, the nano high-viscosity friction reducer system has a core permeability damage rate of 19.66%, higher than conventional slickwater but significantly lower than guar gum breaking fluid. Under reacted acid conditions, an addition of nanoemulsions can transform oil-wet cores into water-wet ones, altering the direction of capillary forces and providing a driving force for imbibition oil recovery, with an imbibition recovery rate as high as 24.89%, 17.38% higher than a group without nanoemulsions. The ability of nanoemulsions to mobilize oil in both micro and macro pores indicates a substantial potential in utilizing fracturing fluid energy to displace oil for enhanced recovery. This study suggests that the nano high-viscosity friction reducers system can not only improve properties such as its viscosity and friction reduction rate, minimizing polymer invasion damage to a formation but also supplement formation energy and displace crude oil through imbibition, thereby achieving an integrated and efficient acid fracturing stimulation and enhanced oil recovery.

Prospects for the use of flow diverter technologies at the Alibekmola oil field

Background: The process of oil production from low-permeability reservoirs has some features and is associated with a number of problems. The main problem is the lack of involvement in the active development of oil reserves in low-permeability zones. Most design documents for the development of low-permeability carbonate reservoirs recommend conventional water injection, which leads to rapid water encroachment of production wells due to water breakthrough from the injection well to the production well through the high-permeability layers or fractures.
 Aim: In the conditions of low-permeability reservoirs of carbonate deposits, there is a need to search for new technologies and development methods that will ensure the economic viability of field development at a late stage.
 Materials and methods: One of the promising technologies that help reduce the level of water cut and involve in the development of an inactive matrix zone low-permeability fractured reservoirs are flow diverter technologies aimed at increasing the sweeping efficiency of productive formations by redistributing filtration flows, reducing or stabilizing water cut, reducing the volume of produced water, obtaining additional oil production.
 Results: This article presents the results of laboratory studies on the selection of optimal flow diverter chemical compositions for the conditions of the Alibekmola oil field.
 Conclusion: Conducted laboratory studies prove the applicability and effectiveness of flow diverter compositions for the conditions of carbonate fractured reservoirs.

Improving the efficiency of reservoir pressure monitoring in low-permeable carbonate reservoirs

he modern development of the resource base of the Volga-Ural oil and gas province is characterized by a reduction in the share of highly productive development facilities. The emphasis is shifting towards the operation of low-productivity collectors. Improving the efficiency of managing such assets requires timely monitoring of the energy state of deposits, reasonable selection of geological and technological measures. The approach to monitoring reservoir pressure in this case should differ from the standard, a combination of the most effective research methods is necessary. In conditions of low productivity, methods based on long-term monitoring of reservoir pressure with subsequent data processing using special techniques have proven themselves well. Ultimately, the combination of various methods for monitoring the energy state of low-yielding carbonate reservoirs allows you to individually create an effective research program that allows you to further manage the development. The presented article is devoted to solving these problems. Keywords: carbonate reservoir; permeability; pressure recovery curve; thermomanometric systems; multi-well retrospective test; control piezometric well stock.

Laboratory studies of induction of flow using vibratory wave draining in carbonate low-permeability reservoirs

The object of the study is a laboratory unit for inducing flow to the well using vibration wave draining in carbonate low-permeability reservoirs. Vibratory wave draining is a method used to stimulate flow draining to the well. The method is based on the fact that mechanical waves generated in the soil can cause the opening of microcracks and pores, which leads to an increase in the fluid flow. Vibratory wave scouring can be effectively used to increase fluid flow in low-permeability carbonate reservoirs. Carbonate reservoirs are a common type of reservoir in the oil and gas industry. They often have low permeability, which makes it difficult to extract fluid. With the help of the plunger device developed in the work, a fluid disturbance was created, thereby creating elastic waves in the conventional well (plastic pipe), which were measured using a manual contact vibrometer. This demonstrated the effectiveness of the vibratory method to increase the well productivity and helped to improve the permeability of the rocks, providing better access to challenge the influx of hydrocarbon products. It is shown that with a significant decrease in the permeability of the formation well zone (FWZ), the flow induction should be started only after the restoration works. Otherwise, the well will be significantly hydrodynamically imperfect due to the quality of the reservoir opening, and the flow of production into the well will occur only through a few separate areas of the reservoir with relatively high permeability, which will lead to uneven production of the reservoir and low return of hydrocarbons. Therefore, it is advisable to use the developed method of influencing the productive layer in low-permeability rocks, such as carbonates with layers of clay, siltstones, argillites, and others, with low formation pressures. The obtained results are based on the generation of vibrations that are transmitted to the wellbore. These vibrations can help break up contaminants and fines in carbonate rocks, facilitating the release of hydrocarbon products and improving permeability.

Experimental evaluation and optimization of improved conductivity of gelling acid etched fractures in deep, low-permeability reservoirs

Stimulation technology is the key to efficient development of deep low-permeability carbonate reservoirs. For such reservoirs, where the porosity and permeability are low, or where the reservoir is far from the borehole. An efficient production increase can only be achieved by using a deep percolation gelling acid fracture technique, maximizing the length of the acid etched fracture to expand the percolation area, and improving the conductivity of the acid etched fracture. A quantitative experimental study of the conductivity of acid etch fracture based on an acid rock tiling instrument, a 3D laser scanner, and an acid etch fracture conductivity evaluation device identified three typical supporting morphologies of gelling acid etch fracture walls: spot, line, and sheet. A systematic quantitative description and evaluation of the etch morphology of rocks etched by acid has been performed. The fracture morphology of acid etchings has been quantitatively evaluated under various experimental conditions such as fracture width, temperature, acid fluid consumption, displacement, and different acid fracture processes and their laws affecting fracture conductivity. The conductivity of acid corrosion fracture increases with the decrease of fracture width, and decreases with the increase of closure stress. The greater the amount of acid used, the higher the fracture conductivity; With the increase of flow Reynolds number, the conductivity of acid corrosion fracture shows a trend of increasing first and then decreasing. The fracture conductivity was compared and analyzed for different property placement conditions under the acid sand carrying technique, and the main effect of the acid etch fracture conductivity was identified. Optimization of high conductivity and deep penetration gelling acid fracturing techniques can help guide the design of acid fracturing and improve stimulation and recovery effects, thus achieving the goal of efficient development of deep, low permeability carbonate reservoirs to increase reserves and production.

Experimental Study of Acid Etching and Conductivity of High-Temperature-Resistant Cross-Linked Acid

Acid fracturing is one of the effective techniques for developing low-permeability carbonate reservoirs economically. With the increasing reservoir depth, the reservoir temperature and closure pressure increase, posing new challenges to the acid system. In this paper, a high-temperature-resistant cross-linked acid system is selected, which maintains a viscosity above 80 mPa·s in the temperature range of 120 °C to 140 °C and can effectively reduce acid leak-off. The acid system can not only open the reservoir and ensure the extension of the fracture, but also reduce the reaction rate between the acid and the reservoir and increase the etching distance. The rock slab acid etching and conductivity tests show that the optimum injection rate is 50 mL/min, the rock etching morphology is channel type, and the conductivity remains above 110 D·cm. However, as the acid concentration decreases, the rock slab conductivity decreases considerably, especially at 10% acid concentration, where the closure pressure rises to 15 MPa, and there is almost no conductivity. In particular, after the acid system is broken, the reacted acid can form a filter cake on the core surface, hindering further intrusion of the residue into the core and reducing reservoir damage. The study shows that high-temperature-resistant cross-linked acid systems can effectively improve the stimulation of deeply fractured carbonate reservoirs at high temperatures.

Effect of different salinity on low permeability carbonate reservoir recovery using a new green polymeric nanocomposites

ABSTRACT Nanoparticles usage and altering mechanisms such as wettability alteration (CA) and interfacial tension (IFT) reduction in carbonate reservoirs are common methods used to recover more oil (nanoparticles-assisted enhanced oil recovery (EOR)) from these reservoirs. ZnO/SiO2/Xanthan as new nanocomposites were introduced at reservoir conditions and different salinity, and results were compared with commercial SiO2 nanoparticles in this study. Scanning electron microscopy (SEM), X-ray diffraction (XRD), energy-dispersive X-ray (EDX), and Brunauer-Emmett-Teller (BET) tests were used for observing morphology and the crystal structure of reservoir. Then, nanocomposites and SiO2 nanocomposites at 0.05 wt. % were used for seeing IFT and CA parameters at reservoir conditions and different salinity. It was found that nanocomposites have better results during IFT and CA tests compared to SiO2 nanoparticles, and nanocomposites were selected for surveying the salinity effect in the presence of nanocomposites on low permeability carbonate porous media with imbibition tests. CA (2 SW, 10 SW) decreased from (86 ̊, 80 ̊) to (79 ̊, 78 ̊) and (75 ̊, 74 ̊) in the presence of nanocomposites and SiO2, respectively, at 60°C and 1800 Psi. Two other important factors that were changed effectively in the presence of nanocomposites were IFT and stability tests. Nanocomposites show stable behavior at different salinity (ZP at 10 SW: 31.37, ZP at 2 SW: −28.00), and IFT decreased in the presence of 2 SW and 10 SW (higher in 2 SW). Finally, recovery factor was increased at both 2 SW and 10 SW in the presence of nanocomposites and reservoir conditions (2SW: 25.1%, 10 SW: 34.1%).

Interaction of Foam and Microemulsion Components in Low-Tension-Gas Flooding

Low-Tension-Foam (LTF) flooding is an emerging enhanced oil recovery technique for low-permeability carbonate reservoirs. Foam capacity is closely related to the salinity environment (or, equivalently, the phase behavior of the oil/water/surfactant system). Therefore, the interactions between microemulsion and foam components are of primary importance in the LTF process. In this study, the phase behavior of an oil/water/surfactant system under equilibrium is analyzed, firstly by assuming perfect mixing. Meanwhile, the formation kinetics of microemulsion are monitored through a novel low-field NMR technique, which is able to provide quantitative assessment on the microemulsion evolution characteristics. Then, foam stability is examined in the absence and in the presence of Winsor-I and Winsor-III type microemulsions. It is revealed that foam stability depends on the oil solubilization (oil swollen micelle size). A decrease in the oil swollen micelle size and micellar structure effectiveness, in conjunction with an increasing salinity, leads to lower foam stability in the presence of a Winsor-III type microemulsion.

Production Forecasting Based on Attribute-Augmented Spatiotemporal Graph Convolutional Network for a Typical Carbonate Reservoir in the Middle East

Production forecasting plays an important role in development plans during the entire period of petroleum exploration and development. Artificial intelligence has been extensively investigated in recent years because of its capacity to extensively analyze and interpret complex data. With the emergence of spatiotemporal models that can integrate graph convolutional networks (GCN) and recurrent neural networks (RNN), it is now possible to achieve multi-well production prediction by considering the impact of interactions between producers and historical production data simultaneously. Moreover, an accurate prediction not only depends on historical production data but also on the influence of neighboring injectors’ historical gas injection rate (GIR). Therefore, based on the assumption that introducing GIR can enhance prediction accuracy, this paper proposes a deep learning-based hybrid production forecasting model that is aimed at considering both the spatiotemporal characteristics of producers and the GIR of neighboring injectors. Specifically, we integrated spatiotemporal characteristics and GIR into an attribute-augmented spatiotemporal graph convolutional network (AST-GCN) and gated recurrent units (GRU) neural network to extract intricate temporal correlations from historical data. The method proposed in this paper has been successfully applied in a well pattern (including five producers and seven gas injectors) in a low-permeability carbonate reservoir in the Middle East. In single well production forecasting, the error of AST-GCN is 63.2%, 37.3%, and 16.1% lower in MedAE, MAE, and RMSE compared with GRU and 62.9%, 44.6%, and 28.9% lower compared with RNS. Similarly, the accuracy of AST-GCN is 15.9% and 35.8% higher than GRU and RNS in single well prediction. In well-pattern production forecasting, the error of AST-GCN is 41.2%, 64.2%, and 75.2% lower in RMSE, MAE, and MedAE compared with RNS, while the accuracy of AST-GCN is 29.3% higher. After different degrees of Gaussian noise are added to the actual data, the average change in AST-GCN is 3.3%, 0.4%, and 1.2% in MedAE, MAE, and RMSE, which indicates the robustness of the proposed model. The results show that the proposed model can consider the production data, gas injection data, and spatial correlation at the same time, which performs well in oil production forecasts.

A simulation study of hydraulic fracturing design in carbonate reservoirs: a middle east oilfield case study

The interactions between hydraulic fracture morphology and fluid transport mechanisms after large-scale fracturing in low-permeability carbonate reservoirs are important factors that could impact post-fracturing productivity. Using an integrated geology-engineering approach that consists of hydraulic fracturing and reservoir simulation, this paper presents the detailed hydraulic fracturing simulation and design of a low-permeability carbonate reservoir in the Middle East based on sweet spot mapping. The fracturing protocol is determined based on productivity charts, which are obtained via sweet spot mapping of the target carbonate reservoir. The daily production of a horizontal well in the reservoir shows an increase from 870 to 2000 bbl/d after the hydraulic fracturing design and implementation, which is the highest among the existing production wells in same oilfield. The results are shown to be consistent with the proposed productivity chart, which suggests that the implemented workflow could be helpful for the large-scale fracturing implementation of similar carbonate reservoirs.

Formation damage reduction during CO2 flooding in low permeability carbonate reservoir with using a new synthesized nanocomposites

Oil reservoir production rates gradually decline as reservoir pressure lowers. There are many causes for this, including precipitation and asphaltene (ASP) deposition. This investigation seeks to assess the performance of Synthetic Zeolite-Zirconia-Cerium oxide (ZZC) nanocomposites (NCs) in the prevention of ASP damage using a coreflooding test under reservoir circumstances. In this research, used SEM, XRD, and EDX analyses to prevent ASP precipitation in the static phase and address ASP precipitation issues in the dynamic CO2 (CF) flooding test. Using Na-ZSM-5 zeolite nanoparticles (NPs), CO2-oil IFT experiments, isotherm models, and CO2 core flooding (CCF) tests at the static stage were carried out in the presence of ZZC. After that, CCF tests at the dynamic stage were created under the static conditions that had been established in order to examine permeability/porosity reduction in porous media. In comparison to Na-ZSM-5 zeolite NPs, ZZC absorbed more ASP. Additionally, ZZC and Na-ZSM-5 zeolite had decreased ASP precipitation when the pressure dropped from 2600 to 1700 Psi. The ASP depositions in the dynamic phase were reduced after adding ZZC, and the permeability/porosity reduction characteristics were enhanced. The results of this study may be used to address ASP precipitation during production phases.

Analysis of factors influencing recovery of low permeability and strong heterogeneous gas reservoirs and establishment of prediction model

Jialingjiang Formation is a typical low permeability carbonate reservoir in Sichuan Basin, which is characterized by strong heterogeneity, low matrix permeability and high-water saturation. Based on seven influencing factors, such as permeability, reservoir thickness and reservoir porosity, this paper evaluates and predicts the oil recovery of Jialingjiang Formation gas reservoir by using two neural network models of multilayer perceptor and radial basis function and nonlinear surface fitting method. The results show that: 1) In the neural network prediction model, the correlation coefficient between the prediction result curve of multilayer perceptron and the original recovery curve reaches 0.88, which is higher than the radial basis function (0.81), indicating that the use of multilayer perceptron can better predict the recovery of gas reservoirs. 2) In the nonlinear curved surface fitting prediction model, the two influencing factors with the greatest linear correlation with the recovery factor, reservoir thickness and gas recovery rate, are selected to fit the prediction model, and the prediction model is obtained. According to the prediction model, the recovery factor is positively correlated with the reservoir thickness and gas recovery rate on the whole. The model can be used to estimate gas recovery from two factors: reservoir thickness and gas recovery rate.

A comprehensive performance evaluation methodology for miscible gas flooding: A case study in a giant carbonate reservoir in Middle East

This work focuses on a typical low-permeability carbonate reservoir in Middle East that has been developed by miscible hydrocarbon (HC) gas flooding for more than 10 years. The oilfield is now suffering from gas channeling, high gas/oil ratio (GOR), and invalid gas circulation. To figure out the reasons and propose an optimized development plan, it is necessary to accurately determine the characteristics and behavior of miscible gas flooding. To achieve this, a comprehensive performance evaluation method for miscible gas flooding is established in this work by integrating production data, inter-well gas tracer test, saturation surveillance, pressure surveillance, minimum miscibility pressure (MMP) variation, and streamline simulation. The following miscible HC gas flooding characteristics are interpreted, including typical gas flow path, miscibility behavior, major controlling factors impacting performance, and the main challenges of the current development scheme, which provides a fundament for proposing mitigation plan. By using this evaluation method, the behavior of gas flow in the ongoing miscible flooding process is precisely characterized, which is a “gravity override-gas coning” mode in which gas override is formed by an upward injected gas flow and then gas flows through gas cap to producers that leads to gas coning, resulting in high GOR and invalid gas circulation. This flow mode mainly resulted from the unsatisfied miscibility that led to gas escaping from miscible phase and gas channeling. Furthermore, it was found out that pressure difference is the dominating factor for gas channeling. In addition, we also found that MMP varies during HC gas injection process due to the change in the oil composition, which emphasizes the importance of recovering and maintaining pressure. Based on these findings obtained from extensive dynamic performance analysis and numerical simulations, an optimization strategy is finally proposed for improving the performance of miscible HC gas flooding.

An improved method of recovery factor estimation for low-permeability carbonate reservoirs

At present, there are limited empirical formulas for recovery factor estimation of carbonate reservoirs in the early stage of development. An improved recovery factor estimation method is established in this paper combining with displacement efficiency, sweep coefficient, well pattern coefficient, utilization factor, and reservoir connectivity coefficient. Among them, the utilization factor and connectivity coefficient is firstly proposed and established by derivation and reservoir simulation considering the characteristics of low-permeability carbonate reservoirs. The method is applied to M oilfield, and the estimation results are compared with other empirical formulas and field development calibration results, which shows good estimation accuracy.

First Multistage Fracturing of a Horizontal Well Drilled in a Tight Carbonate Reservoir in UAE

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203226, “First Multistage Fracturing of Horizontal Well Drilled in a Conventional Tight Carbonate Reservoir in an Onshore Field in the UAE: Challenges and Lessons Learned,” by Muhammad Aftab, SPE, Noor Talib, and Maad Subaihi, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. The reservoir upon which this case study is focused is a tight, low-permeability carbonate reservoir with thin layers. The objective of the field case was to increase and sustain productivity of a pilot well consisting of an openhole completion. The complete paper summarizes the design processes, selection criteria, challenges, and lessons learned during design and execution phases. The study may provide a potential approach for selecting the proper hydraulic fracturing method and technique in similar cases. Introduction Reservoir X is divided into six layers. Layers X-3 through X-6 have reasonable porosity development; valid pressure points exist in X-3 and X-6. Pumpout was performed while collecting samples from X-3 and X-6, followed by short buildups. Production-logging-tool measurement was performed and found two major oil-producing layers across X-3 (60% of total production) and X-6 (40% of total production). The remaining intervals of the perforation were almost inactive. Petrophyscial and testing results of vertical Well A resulted in a decision to drill a horizontal oil producer (Well B) through Layer X-3. Well B was steered with a 2,220-ft horizontal length, out of which 1,930 ft was inside X-3 and 290 ft were above X-3 be-cause of a fault throw of 16 ft true vertical depth. The well was steered with a horizontal length of 2,080 ft in X-6. Well B was completed with a 3½-in. completion and horizontal section as an openhole. Matrix stimulation using coiled tubing was performed with 15% hydrochloric acid in Well B. The well ceased to flow after 2 weeks of declining production. Rapid pressure depletion was observed in Well B. Localized depletion around the wellbore was anticipated because of poor matrix/matrix connectivity. After comprehensive studies and risk assessments, the decision was made to recomplete Well B with a cemented fracturing string to perform hydraulic fracturing with the plug-and-perf technique. This technique will allow flexibility of stage count and stage spacing and a multi-cluster design to maximize the stimulated reservoir volume (SRV) along the upper, middle, and lower layers. In addition, the operator and service provider collaborated to enhance this design through a zero-overflush technique with diverting agents. The complete paper provides a detailed discussion of the core measurement and 1D mechanical Earth model used in the hydraulic fracturing design. Hydraulic Fracturing Design The main challenge in fracturing Well B was to ensure that the fracture generated is contained within the reservoir. Well B is completed in two layers (X-3 and X-6). The bottom part of the well is in X-6 and close to another underlying reservoir (Fig. 1).

Research of complex fracture acid fracturing technology in low permeability carbonate reservoir

Based on the analysis of the characteristics of the low-permeability carbonate reservoir, this paper has carried out studies on the adaptability of geological conditions, the adaptability of rock mechanics conditions and the characteristics of horizontal stress of the reservoir, etc., and demonstrated the feasibility of the acid fracturing of the low-permeability carbonate reservoir with complex fractures. In view of the poor connectivity of low-permeability carbonate reservoirs and the unsatisfactory effect of conventional acid fracturing, a “large scale + high pump rate” process idea of complex fracture acid fracturing technology was formed through the simulation of process parameters and optimization of construction pipe string, so as to expand the reservoir stimulation volume and improve the communication scope.

Extensive Well-Testing Operations Provide Insight Into Khuff Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203441, “Lessons Learned From Extensive Well-Testing Operations in Khuff Formations Offshore Abu Dhabi,” by Florian Hollaender, SPE, Schlumberger, and Mahmoud Basioni and Ahmed Yahya Al Blooshi, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually from 9-12 November. The paper has not been peer reviewed. An extensive appraisal campaign was performed in the Khuff reservoirs offshore Abu Dhabi, with multiple appraisal wells drilled in different fields. Those wells were evaluated using detailed logging campaigns and then subjected to well tests, usually through drillstem testing for targeted intervals. The interpretation of well tests, combined with advanced petrophysical analysis, formation-test data, and production logs, provided insight into the nature of the Khuff reservoirs. A wide range of responses was observed, from tight to highly productive, but not necessarily with clear previous indications of deliverability or inflow intervals. Overview of the Khuff Formations The key characteristics of the Khuff formations offshore Abu Dhabi have been well-documented in previous work and can be summarized by the following: Low porosity and permeability carbonate reservoirs, where natural fractures are critical contributors to flow Properties vary widely laterally, with significant uncertainty regarding connectivity Variations in stress and petrophysical properties can be significant and affected by diagenetic and tectonic history These reservoirs present significant challenges for development planning. Previous studies have shown that it can be difficult to relate production performance to standard petrophysical analysis directly and that the presence of fractures - in particular, critically stressed fractures - in the vicinity of the wellbore is an essential factor for production performance. Productivity also was found to vary by several orders of magnitude within the same reservoir depending on the field and lateral location of a given well. The presence of natural fractures has been recognized as a major contributor to flow in tight gas reservoirs; however, this raises several questions related to assessing formation potential. First, the nature of the fractures must be evaluated. Some will contribute to production, while others will remain sealed. Equally importantly, identifying zones with promising porosity developments is not a solid indicator of production expectations. Well-Test Observations With more than 20 drillstem tests performed in the Khuff reservoirs during a 4-year period, the first observation is the wide range of reservoir responses encountered, with an apparent lack of consistency within a given reservoir or field.

3D seismic discontinuity attributes analyses for low – permeability reservoir sand fractures characterisation: an onshore example from Niger delta, Nigeria

ABSTRACT In hydrocarbon exploration, fractures act as possible pathways for hydrocarbon flow especially in low-permeable siliciclastic reservoirs and carbonate reservoir layers. These fractures on typical seismic section are designatesub-seismic scale structures, occur below seismic resolution and thus difficult to detect on seismic section. This study aims to predict and characterise sub-seismic scale fractures within low-permeability siliciclastic reservoirs of Agbada Formation in “Kin” Field onshore Niger Delta basin by using discontinuity attributes i.e. similarity and curvature. The input seismic data of the study field was initially conditioned using the dip steering algorithm to improve the image quality of fractures in the data. Time-slices were extracted within the horizons of interest for seismic attribute analysis. Conventional log from porosity density was used to validate the interpreted fractures within the borehole environment. The attribute analyses result at time-slices 2024 ms, 2100 ms and 2197 ms show subtle features i.e. fractures with predominant trends NW – SE and NE – SW. A multi-attribute analysis was performed to optimise fractures prediction. Further results show relatively high fracture density at the western central and south eastern regions of the study area. Therefore, these regions could be inferred as potential hydrocarbon zones and locations for future wells placement.

Predicting the Surveillance Data in a Low-Permeability Carbonate Reservoir with the Machine-Learning Tree Boosting Method and the Time-Segmented Feature Extraction

Predictive analysis of the reservoir surveillance data is crucial for the high-efficiency management of oil and gas reservoirs. Here we introduce a new approach to reservoir surveillance that uses the machine learning tree boosting method to forecast production data. In this method, the prediction target is the decline rate of oil production at a given time for one well in the low-permeability carbonate reservoir. The input data to train the model includes reservoir production data (e.g., oil rate, water cut, gas oil ratio (GOR)) and reservoir operation data (e.g., history of choke size and shut-down activity) of 91 producers in this reservoir for the last 20 years. The tree boosting algorithm aims to quantitatively uncover the complicated hidden patterns between the target prediction parameter and other monitored data of a high variety, through state-of-the-art automatic classification and multiple linear regression algorithms. We also introduce a segmentation technique that divides the multivariate time-series production and operation data into a sequence of discrete segments. This feature extraction technique can transfer key features, based on expert knowledge derived from the in-reservoir surveillance, into a data form that is suitable for the machine learning algorithm. Compared with traditional methods, the approach proposed in this article can handle surveillance data in a multivariate time-series form with different strengths of internal correlation. It also provides capabilities for data obtained in multiple wells, measured from multiple sources, as well as of multiple attributes. Our application results indicate that this approach is quite promising in capturing the complicated patterns between the target variable and several other explanatory variables, and thus in predicting the daily oil production rate.

Ichnofabrics and their roles in the modification of petrophysical properties: A case study of the Ordovician Majiagou Formation, northwest Henan Province, China

The carbonate rocks of the Ordovician Majiagou Formation from the northwestern part of Henan Province and their diverse trace fossils provide an outcrop analogue for bioturbated, low porosity and low permeability carbonate reservoirs. Three ichnofabrics can be defined based on the ichnotaxonomy, ichnodiversities, individual abundances and overall bioturbation indices. The Balanoglossites ichnofabric represented medium to relatively high-energy sedimentary environments such as intertidal zone and subtidal shoals in the carbonate platform. The Planolites ichnofabric suggested relatively low-energy, protected sedimentary environments such as lagoons in a restricted carbonate platform, but also occurs in the deeper-water depressions in the open carbonate platform. The Chondrites ichnofabric characterized low-energy and reduced oxygen conditions, with burrows penetrating below a shallow redox interface in deeper-water settings that include the distal slope as well as local depressions in the open carbonate platform. Our analysis suggests that the modifications of petrophysical parameters are controlled or influenced by the ichnofabric characteristics (burrow architecture, burrow cross-cutting relationship, degree of bioturbation and burrow connectivity), the permeability contrast between burrow-fills and matrix, and the dolomitization of burrow-fills. The micritic host sediments have negligible porosity and permeability. The bioturbated sediments have significant differences in fabric, texture, porosity and permeability. The burrow-fills are very commonly dolomitised. Each of the burrow-types can enhance reservoir properties, but the greatest differences are associated with the Balanoglossites ichnofabric, in which porosity and permeability can reach over 2% and 70 mD. Preliminary stratigraphic studies indicate that reservoir potential in the subsurface will be linked to an understanding of the distribution of shoal and intertidal facies as well as their associated Balanoglossites ichnofabrics.