Fractured Wells Research Articles

Fracture stratigraphy in oil-rich shale of the Upper Xiaganchaigou Formation (upper Eocene), western Qaidam Basin

Natural fractures in wells from oil-rich shale of the Upper Xiaganchaigou Formation in Qaidam Basin, the largest Cenozoic sedimentary basin in the Tibetan Plateau, vary systematically by stratigraphic position, allowing reconstruction of fracture generation processes during regional tectonic deformation. Compacted fractures, layer-bounded fractures, and low-angle (or bed-parallel) fractures were widely identified in oil-rich shale cores obtained from vertical wells. The layer-bounded fractures can be subdivided into two sets: one prevalent in light-colored (low gamma-ray) stiff layers and arrested by dark-colored (high gamma-ray) compliant layers, the other set primarily confined to the dark-colored compliant layers. The strikes of layer-bounded fractures, revealed by horizontal well FMI logs, are dominantly N60°-80°E and N10°-30°E within the light and dark intervals respectively. These strikes are consistent with natural hydraulic fracturing of the light layers during the Oligocene and the dark layers during the Middle Miocene-Holocene, based on a regional anticlockwise rotation of the compressional strain orientation. The abutment of layer-bounded fractures against low-angle (or bed-parallel) fractures in dark layers implies that the low-angle fractures were hydraulically fractured under a vertical least compressive stress during the Early Miocene, which produced the most intense tectonic compression. Layer-bounded fractures generally remain unmineralized in the dark layers but were mineralized in the light layers, suggesting that fractures confined in light layers would not decrease the sealing capacity of the shale oil system and fractures confined in dark layers can increase the pore space of shale oil storage. The Oligocene and Early Miocene fractures represented mechanical flaws that affected the initiation of Middle Miocene-Holocene fractures, implying that all natural fractures may alter hydraulic fracture stimulations to some extent.

Fluid inclusion evidence for overpressure-induced self-sealing and accumulation of deep shale gas

Shale oil and gas exploration and development are extending to greater depths, and it is important to understand the accumulation mechanisms of shale oil and gas. Here we conducted a case study in the Upper Ordovician Wufeng Formation–Lower Silurian Longmaxi Formation in the Ningxi area, Sichuan Basin, southwest China, by using petrological and fluid inclusion investigation to determine the processes involved during the overpressure-induced self-sealing accumulation of deep shale gas. Results show that fibrous quartz–calcite veins in the source rocks contain abundant gas inclusions and coeval two-phase gas–liquid aqueous inclusions. The gas inclusions are relatively uniform, translucent to transparent, single-phase inclusions with a high density, indicative of a closed shale system. The gas inclusions record varying levels of fluid overpressure (115.23–169.46 MPa), with a paleo-pressure coefficient of 2.12–2.98. Fluid overpressure and self-sealing resulted in shale gas accumulation, with bedding-parallel and laminar fractures acting as important migration pathways, which improved the horizontal porosity and permeability of the shale. These processes are common and important phenomena in petroleum systems. Unconventional oil and gas development commonly requires horizontal fracturing of wells to form a fracture network, which can improve the production capacity.

Improving the efficiency of hydraulic fracturing in wells with depleted gas reservoirs

The reasons for the low production rate of gas wells in depleted gas reservoirs are presented, including low natural permeability of productive formations and contamination of the bottomhole zone with solid phase and liquid. The methods of gas inflow stimulation to the bottom of wells are presented, among which hydraulic fracturing (HF) is worthy of attention for low permeability formations and deterioration of the bottomhole zone. The essence of hydraulic fracturing is described. Conventional and high-power hydraulic fracturing, its technology, scope, materials and chemicals used, and technological efficiency are characterized. During hydraulic fracturing in wells at depths of more than 600 m, to which the main proven gas reserves are confined, vertical and near-vertical fractures will mainly form. With a small reservoir thickness, vertical fractures can damage the cement stone behind the production casing, which in depleted gas reservoirs will help create conductive channels from the gas reservoir to the upper horizons. With a vertical fracture, gas flow to the well will be in one direction along the fracture and other volumes of the wellbore zone within the fracture radius will not be fully covered by filtration. To improve the efficiency of hydraulic fracturing in wells in depleted gas reservoirs, it is proposed to create a horizontal fracture in thin formations or several vertical fractures in formations of large thickness by preliminary hydraulic sandblasting perforation (HSP) or gas hydrosandblasting perforation (GHBP). When preliminary creating horizontal channels in the bottomhole zone, tubing with a perforator is gradually rotated to a certain angle, and when creating vertical channels, they are gradually raised to a certain height. After the perforation channels are created, hydraulic fracturing is performed. With the sequential use of hydraulic sandblasting perforation and hydraulic fracturing, it is possible to create a grid of cracks of increased length in the bottomhole zone in the specified directions. Using known analytical dependences, the length of individual perforation channels during gas-hydro-sandblasting perforation with a nozzle diameter of 4.5 and 6 mm in the perforator and the fracture radius during hydraulic fracturing were determined. The degree of increase in gas flow rate separately from hydraulic fracturing and hydraulic fracturing from their sequential implementation is estimated

Development of Large-Scale Tight Gas Sandstone Reservoirs and Recommendations for Stable Production—The Example of the Sulige Gas Field in the Ordos Basin

The natural gas reserves and gas recovery rate of tight gas sandstone reservoirs in the Sulige gas field in the Ordos Basin play a crucial role in China’s natural gas industry. This study aims to enhance the stable production time of the gas field by summarizing the geological characteristics of the tight gas sandstone reservoirs in the Sulige gas field, discussing the challenges in the development of the gas field, and providing recommendations for the development of the reservoirs. The results show that the matrix reservoir properties, effective sand body size, and gas-bearing properties of tight sandstone gas reservoirs in the Sulige gas field exhibit strong heterogeneity characteristics, and the western and northern parts of the basin edge are gas-water mixed storage areas. There are obvious differences in gas well production, cumulative production, production decline rate, and single well dynamic control reserves in different regions. The recovery of gas reservoirs is primarily influenced by reservoir quality and development well pattern. Increasing the well density increases from 1.5/km2 to 4/km2 in the gas field enrichment area, can raise the corresponding recovery rate from 26.0% to about 50% under the existing economic and technical conditions. Therefore, ensuring a stable production of the tight gas sandstone reservoirs in this gas field is challenging. To achieve a long-term stable production of the gas field, it is necessary to promote the refined reservoir description technology and improve the production through various measures such as replenishing fractures in wells with depleted fractures, sidetracking horizontal wells, and re-fracturing, thereby improving the reserve utilization degree. Moreover, implementing the negative pressure gas recovery technology as soon as possible can restore the production capacity of near-depletion wells.

Formulation optimization of materials used in temporary plugging diversion between fracture front end and cluster in shale gas: From laboratory research to field application

The staged and multi-cluster fracturing of horizontal wells is the main fracturing technology used for shale gas reservoir development. Temporary plugging diversion (TPD) is an important technical means to realize a uniform propagation of hydraulic fractures and avoid problems such as frac hits (i.e., well-to-well interference). Although this technology has been extensively used worldwide, field monitoring results have shown that temporary plugging cannot effectively improve the nonuniform propagation of multiple fractures. The fundamental reason is the lack of an organic combination of laboratory research and field application. To solve this problem, this study investigated the reservoir adaptability and plugging performance of three types of temporary plugging agent (TPAs), namely, powder, particle, and fiber, used in the fracturing of wells in the Weiyuan (WY) shale gas field, Sichuan, China, using a pressure-bearing capacity test device for three dimensional (3D)-printing-simulated TPA. A calculation method for the plugging efficiency of the TPA was established, and the ratio and concentration of the TPA were optimized under different fracture widths. The similarity criterion was used to calculate the amount of TPA required for different fracture widths. A field application chart of the TPA was formulated, and a method that connects laboratory research and field application was established. The results showed that the three TPAs have good reservoir adaptability and degradation performance. It is recommended to use 200–400 mesh powder + 6 mm fiber with different concentrations and dosages when performing temporary plugging and fracturing at the front end of 1–3 mm fractures. In the case of inter-cluster TPD for a fracture width of 4–6 mm, a combination of 20 mesh powder + 6 mm fiber + 1–3 mm particles is recommended. The field application results showed that the pressure increased significantly at the front end of the fractures and during inter-cluster temporary plugging when the plugging agent was in place, and there were no frac hits in the adjacent wells. This paper provides a practical research method for hydraulic fracturing involving temporary plugging, from laboratory research to engineering application.

Natural Fractures in Low-Permeability Sandstone Reservoirs in the LD-A HPHT Gas Field, Yinggehai Basin: Implications for Hydrocarbon Exploration and Development

Research on the characteristics and distribution of natural fractures is of great importance for the exploration and development of low-permeability sandstone gas reservoirs. In this study, fracture identification and characterization were carried out using cores and imaging logging. Then, comprehensive fracture development indicators were constructed to predict the distribution of fractures in wells by conventional logging. The main factors that affect the development of natural fractures and the implications of fractures on hydrocarbon exploration and development were discussed. The results showed that the natural fractures were mainly low-angle tectonic fractures in sandstone reservoirs. Most of fractures are unfilled, but the distribution of the fractures in the thin sections has a discrete fracture structure, indicating that the connectivity of the fracture system is poor. The development of natural fractures is mainly influenced by rock strength, petrographic composition, and petrology, and the fractures are more developed in sandstones with a higher content of brittle minerals. The fracture densities are mainly distributed below 0.05 m/m and up to 0.1 m/m. In the present in situ stress state, all of the natural fractures in the LD-A gas field are invalid fractures. The critical pressure of the natural fracture is approximately 16.5–25.4 MP/km; when the pore pressure exceeds this value, the fractures become effective fractures. These results provide new geological knowledge and guidance for the exploration and development of LD-A gas fields and other low-permeability tight sandstone reservoirs.

The Fractured Model Study of Low-Permeability Reservoir in Xinli Oil Field

With the development of the petroleum industry, the importance of low-permeability reservoirs becomes clear. The fracture, which serves as the notable characteristic of a low-permeability reservoir, controls the flow system of reservoir fluid and restrains the development effect. Finding ways to recognize the fracture by using the normal data and building the fracture 3-D model are the important and difficult points of low-permeability development. According to this problem, the authors use a helpful probe. First, from similar outcrop and drilling core study of the fractured original model, the knowledge base of the fracture was built. Second, based on the analysis of the principle of dual-later log identification fracture, the core calibration was used to make logging, and using dual-later log, the fracture in wells was recognized. Third, based on the analysis of the principle of the fractal kriging method, the inter-well fractures were predicted. Finally, the 3-D model of fracture was built with fractural random simulation. The result shows that the 3-D model is in accordance with the fact of the development. So, the method is correct.

Assessing geodynamic activity of rock by the borehole survey results

Research objective is to assess the modern geodynamic environment of the geological environment through borehole measurements of signals of geoacoustic emission and electromagnetic radiation. Research relevance is due to the need to identify geodynamically active zones and areas of increased rock fracturing in wells. Methods of research. Rock geodynamic activity was studied in a well of the North-Taratashsky area of a magnetite quartzite deposit in the Chelyabinsk region. MESh-42 hardware and software complex designed for synchronous registration of geoacoustic emission and electromagnetic radiation signals was used to solve this problem. Geoacoustic emission (GAE) and electromagnetic radiation (EMR) signals were recorded using the shuttle logging technique, which makes it possible to identify zones of rock geodynamic activity along well sections and track the dynamics of these sections in time. Results. The results of the method of geoacoustic emission and electromagnetic radiation signals shuttle logging in well no. 7 of the North-Taratashsky area are shown. Conclusions. In the course of geoacoustic emission and electromagnetic radiation signals studies in well no. 7 of the Severo-Taratashsky area according to the shuttle logging method, zones of increased stress in the geological environment and areas of increased fracture formation were identified, which, in turn, made it possible to subdivide the studied interval according to the geodynamic activity of rocks

Insights into the mechanical stratigraphy and vertical fracture patterns in tight oil sandstones: The Upper Triassic Yanchang Formation in the eastern Ordos Basin, China

Vertical fracture patterns are mapped in the outcrops to analyze the impact of mechanical stratigraphy on vertical fractures in the relatively undeformed Upper Triassic tight oil sandstones of the Yanchang Formation along Yanhe River in the east Ordos Basin, China. The relationship between natural fractures and different bounding interfaces are analyzed based on rock relative strength measurement by N-type Schmidt Hammer, fracture and facies description in the outcrops. According to the probability of the bounding interface terminating natural fractures being more than 20%, seven types of mechanical interfaces terminating fracture longitudinal propagation are identified, namely 1) the interface of laminae-set or laminae co-sets, 2) bedding surface interface, 3) accretionary interface, 4) mudstone interbed, 5) mudstone barrier, 6) calcareous barrier and 7) depositional scour interface. According to fracture sizes and the mechanical interfaces which constrain fracture propagation, the vertical fractures are divided into micro-scale, small-scale, meso-scale and macro-scale ones. Three possible vertical fracture patterns in various sedimentary microfacies of the shallow water delta deposits are discussed based on field outcrop observation, the restriction capacities of different mechanical interfaces and the temporally changing tectonic stress. Finally, the application of vertical fracture patterns for subsurface fracture prediction is carried out in the Ansai Oilfield in the eastern Ordos Basin, China. The predicted fractures in wells are consistent with the fractures obtained from cores and conventional logs. This study links sedimentary stratigraphy, mechanical stratigraphy and natural fractures in the tight oil sandstones within a relatively undeformed setting, meanwhile unravels the vertical fracture patterns in different sedimentary microfacies of the shallow water delta deposits in the study area. The results will thus guide subsurface fracture prediction between wells in the tight oil sandstones of the eastern Ordos Basin.

Technological solutions for well construction in high-viscous shale hydrocarbon fields

The article discusses the main technological processes of well construction for the production of high-viscosity hydrocarbons from productive lowporosity reservoirs with high temperature and pressure conditions, which include shale deposits of Bazhenov formation. According to the results of the review and analysis of existing solutions in the development of this deposits, the following measures were justified and proposed: construction of branched multi-hole azimuth horizontal wells, implementation of selective multi-stage hydraulic fracturing in the productive formation; the use of oil-based process fluids when opening the reservoir, the use of plugging materials for isolation of the reservoir, the hardening product of which is represented by thermally stable hydrate phases (hydrobasic hydrosilicates). Вranched wells have a long horizontal end (about 1 000 meters or more). Only a part of the horizontal section works effectively, which is the basis for the development and application of the staged, both in time and along the strike, hydraulic fracturing method. At the level of the invention, a method and apparatus for carrying out multistage selective hydraulic fracturing in wells with horizontal completion have been developed. The article describes a method for implementing multistage selective hydraulic fracturing, comparing this method with the existing ones. Much attention is given to the need to use hydrocarbon-based solutions for the initial opening the reservoir, to use cement slurries from composite materials to separate the reservoir, the hardening product of which is a stone formed by low-basic calcium hydrosilicate.

Improvement of Fracture Network Modeling in Fractured Reservoirs Using Conditioning and Geostatistical Method

Abstract The fracture network in hydrocarbon reservoirs plays a major role in reservoir fluid transfer to production wells. Modeling of fracture in fractured reservoir is often done randomly. Modelling is based on image logs and core information. Because the information is available in a small number of wells, the model is not reliable and this problem makes it impossible to predict the correct flow rate and the amount of wells produced. In this study, an algorithm based on primary and secondary data for fracture network modelling in one of the southwest fields of Iran has been presented. The initial data include aperture fracture and fracture density, and secondary data includes petrophysical data, i.e. electrical resistance and resistance logs used to scale-up characteristics of fracture in wells. In this study, we tried to increase the accuracy of modelling by using modelling conditionality on existing and constructed data. Gaussian conditional simulation produces a set of realizations on which non-linear statistics can be readily available. In this way, information was entered into the model in areas where fracture was predicted to exist. Using the turning bands co-simulation method in geostatistic, the fracture characteristics were simulated in wells that were not available. Using the results of the 3D model, the fracture of the reservoir was re-constructed. The results showed that the modelling performed in this study has been able to increase the fracture prediction accuracy and their properties in fracture density by about 9% and in the fracture opening by about 5%.

Verification of Fracture Reorientation and Analysis of Influence Factors in Multiple Fracturing Treatment

A fracture will be initiated and propagated along the direction of maximum horizontal stress in fracturing treatment; however, in refracturing stimulation, the new fracture may be initiated and propagated along a different direction from the initial one. This is defined as a fracture reorientation. It is difficult to predict fracture reorientation due to the variation of formation properties after long-term production. To verify the existence of fracture reorientation and analyze its influencing factors in multiple fracturing treatment, experimental and numerical simulations are presented in this paper. Firstly, multiple fracturing stimulation is carried out with a self-assembled large true triaxial apparatus, and the fracture reorientation is successfully induced by changing the injection pressure and initial stresses in multiple fracturing processes. Then, numerical coupled hydromechanical modeling of the actual field production and injection well pattern is performed. In particular, the stress reversal region, which indicates the distance of fracture reorientation, and the factors that influence the reorientation are analyzed. The laboratory experiment and numerical simulation results show that the fracture reoriented angle obtained can be perpendicular to the initial fracture. Stress field and formation pressure are the two main factors that influence the fracture reorientation. With higher pressure differences and lower initial horizontal stress differences, the area in which it is possible to initiate reoriented fracture will be larger. The fractures of wells in the early production stage are hard to reorient due to the high formation and borehole pressure difference, and the fracture reorientation area will be expanded until the pressure difference is low to a certain value. This research result can guide oilfield stimulation treatments.

SELECTION OF A COMPLEX OF WELL HYDRODYNAMIC STUDIES FOR RELIABLE FORECASTING OF RESERVOIR PARAMETERS AT VISHNYOVSKOE FIELD

Field studies of wells and reservoirs are becoming increasingly important as a tool for assessing the effectiveness of the measures applied. So, for a better understanding of the water flooding process of the US21 oil reservoir in 2019, hydrodynamic studies were carried out in three areas with low and increased average values of reservoir pressure in the Vishnyovskoye field: by level recovery curve method, by pressure drop curve method, by method of taking up water into well and by pressure testing. The paper provides an interpretation of the conducted field research and an assessment of the effectiveness of their application. The duration of registration of the level buildup curve was determined, sufficient for a reliable forecast of reservoir pressure, numerical modeling was carried out in the software package «Sapfir». Analysis of pressure drawdown curves allows diagnosing the presence of autohydraulic fractures in wells where the formation was not fractured. The efficiency of application of the method of adding service water to the annular space of the well to reduce the time for determining the formation pressure was defined, and at the stage of planning the studies, numerical modeling of the creation of an impulse by stopping and starting up the wells was carried out, the analysis of the results of pressure testing of the US21 formation of the Vishnyovskoe field was given.

Mixed-integer linear programming for scheduling unconventional oil field development

The scheduling of drilling and hydraulic fracturing of wells in an unconventional oil field plays an important role in the profitability of the field. A key challenge arising in this problem is the requirement that neither drilling nor oil production can be done at wells within a specified neighborhood of a well being fractured. We propose a novel mixed-integer linear programming (MILP) formulation for determining a schedule for drilling and fracturing wells in an unconventional oil field. We also derive an alternative formulation which provides stronger relaxations. In order to apply the MILP model for scheduling large fields, we derive a rolling horizon approach that solves a sequence of coarse time-scale MILP instances to obtain a solution at the daily time scale. We benchmark our MILP-based rolling horizon approach against a baseline scheduling algorithm in which wells are developed in the order of their discounted production revenue. Our experiments on synthetically generated instances demonstrate that our MILP-based rolling horizon approach can improve profitability of a field by 4–6%.

Analysis of well stress with the effect of natural fracture nearby wellbore during hydraulic fracturing in shale gas wells

Sustained Casing Pressure (SCP) and production casing deformation in shale gas wells have been of growing interest in the industry, which should be attributed to the failure of cement sheath and casing respectively during the hydraulic fracturing process. Natural fractures are widely developed in shale formation and show tight connection with casing deformation. However, the effect of natural fracture nearby wellbore on casing deformation have hardly been investigated in previous references. Based on this situation, a staged analytical model for stress calculation of casing-cement-formation system (CCFS) is established, which fully incorporates the effect of natural fracture nearby wellbore during hydraulic fracturing. The calculation results of new analytical model are in good agreement with the numerical method by staged finite element. Moreover, the stress variation of CCFS under the effect of natural fracture is revealed by employing the simulation of field data from Weiyuan shale gas field. Results illustrate that the circumference stress at interface between casing and cement (interface I) turns to compression from tension conditions once the natural fracture effect is generated, moreover, both the radial and circumference stress increase greatly considering the effect of natural fracture. Further, optimizing suggestions for the design of fracturing, casing and cement sheath are provided through sensitivity analysis. It implies that the well stages with close distance fractures (the limit distance of calculation example in this research is 1.4 m) should be avoided hydraulic fracturing in the well design for the integrity of casing and cement sheath, Nevertheless, the increasement of production casing thickness and fracturing fluid temperature can dramatically reduce the risk of casing deformation and failure of cement sheath, if the well stages with fractures can not be avoided rightly.

DEVELOPMENT OF MULTI-STAGE FRACTURING TECHNOLOGIES

Background Due to the increasing share of hard-to-recover oil reserves, systems for well completion and intensification of fluid inflows are being improved. One of the most effective methods for producing hard-to-recover reserves is the drilling of horizontal wells with multi-stage hydraulic fracturing. This article is devoted to well completion technology with using controlled frac sleeves, which are controlled by the SandHawk tool on coil tubing. The article describes a Various types of frac sleeves, downhole drill stem assembly for preparing the well, for open and close ports by the SandHawk. Aims and Objectives Analysis the development of multi-stage fracturing and study the SandHawk tool for multi-stage fracturing in wells with a horizontal section at the Priobskoye field. Results The analysis of development and improvement of technologies for secondary drilling in wells with a horizontal section at the Priobskoye field was carried out.

Identifying cross-well fracture connections using the dissolved oxygen alteration method

Determining how wells in fractured crystalline bedrock are interconnected is essential in defining contaminant flow paths and in interpreting water quality data from wells. Although various tracers and geophysical techniques have been used with success, the high cost or logistics may restrict their implementation. This study demonstrates a low-cost technique for identifying fracture connections between wells by combining the dissolved oxygen alteration method (DOAM) with cross borehole hydraulic pumping tests. Following the alteration of the dissolved oxygen (DO) profile in the observation well through bubbler aeration, an interconnected well is pumped, which results in changes in borehole flow in the aerated observation well. The DO profile in the observation well is monitored over time to characterize the changes in borehole flow and identify fractures that hydraulically connect to the pumping well. The method was demonstrated at three test sites in Storrs, Connecticut. Each site has two or three interconnecting wells in fractured crystalline bedrock and varying flow conditions. The DOAM successfully identified interconnecting fractures in wells 15–84 m apart.

A numerical study on land subsidence due to extensive overexploitation of groundwater in Aliabad plain, Qom-Iran

Over the last decade, many areas of Iran have been increased in suffering from land subsidence due to a large exploitation of groundwater, needed to cope with the water scarcity caused by low precipitation. The plateau of Qom, especially the area of Aliabad village (Aliabad plain), has encountered many problems due to subsidence which occurs as cracks in building walls and fractures in wells. In this paper, we are going to evaluate land subsidence in some parts of Qom plateau, in particular Aliabad plain, by a numerical model (PLAXIS® 3D; v1.6) considering aquifer pressure changes, hydrological and geotechnical data. Results of the study reveal that since 2001–2013, the average groundwater level decline was measured 26.35 m and the corresponding subsidence had been 0–76 cm in different areas of the plain. Response of the saturated geologic units toward the changes in ground water level due to groundwater extraction and, in turn, land subsidence depends on the characteristics of geological materials in the units. Moreover, the units containing a combination of grain and fine soil, such as sand and clay which are completely different in the geotechnical parameters, tend to react differently due to all changes in the groundwater level.

Technology Focus: Hydraulic Fracturing (March 2017)

Technology Focus Hydraulic fracturing is widely used all over the world, and in the Middle East in particular. Although superhigh-quality reservoirs do not need stimulation, the current expansion of reserves is mostly in newly found tight and unconventional resources that require extensive multi-stage fracturing for commercial production. Saudi Aramco embarked on stimulation and fracturing of wells at the beginning of its nonassociated conventional gas development endeavor and has been expanding and improving continuously in the areas of fracture design, use of novel materials, and field implementation. With newly discovered fields and the extension of existing areas, the challenges related to reservoir heterogeneity, tight rock, layered systems, and field maturity have led to innovative ideas and to testing and application of technologies. The use of biodegradable novel diversion systems (NDSs) has allowed fracturing multiple intervals in a single-stage operation, thereby reducing time and significantly cutting operational cost. On the basis of petrophysics and reservoir and geomechanical characteristics, multiple mesh sizes of an NDS are carefully designed and used to divert fluids in the wellbore, ensure simultaneous treatment of lower-quality intervals, and control excessive leakoff inside the fracture, creating longer and planar fractures for improved production. Diagnostics using production logging, temperature logs, and injecting and measuring nonradioactive tracers have shown expected production contribution and increase from target intervals, in both acid- and proppant-fracturing treatments. The superiority of NDSs lies in their natural formulation, simultaneous use in near-well and far-field applications, robustness in creating barriers and diversions, and easily degradable nature and flowback. Among other technology being developed and adopted in Saudi Arabia is the use of seawater-based fracturing fluids that will save the more-valuable fresh water. The laboratory experiments and the few field applications to date have shown stability at high temperatures and pressures, compatibility with formation fluids and fracturing additives, and resilience against scale formation. The use of seawater will serve the environment tremendously and will provide substantial economic benefits in remote areas where access to fresh water is challenging and costly. Saudi Aramco also has initiated the use of local sand as proppants combined with the channel fracturing technique, where proppants serve as pillars supporting and maintaining the induced fractures, keeping them open while the actual fracture conductivity is provided by the open areas within the system. The crushing of pillars by high in-situ stress and the friable quality of sand and consequent release of fines are controlled and contained by the use of resin during the treatment. This technology is also designed to reduce fracturing cost by eliminating more-expensive intermediate-strength proppant (ISP) or high-strength proppant (HSP) during channel fracturing. Sand cannot substitute for ISP or HSP in conventional fracturing because of its low compressive strength and friable nature. The economic advantage achieved by the use of new technologies will help expansion, exploration, drilling, and fracturing in new frontiers and territories. The world’s increasing energy demand, which, for the most part, is hydrocarbon dependent, requires growth and advancement in the oil and gas industry, increasingly environmentally friendly practices, the use of more natural resources, and the application of innovative ideas and new technology that will reduce development and management cost and increase efficiency and effectiveness. Recommended additional reading at OnePetro: www.onepetro.org. SPE 180207 Effects of Hydraulic Fractures on the Treatment of Condensate by Huff ’n’ Puff Gas Injection in Eagle Ford Shale by S. Yang, University of Calgary, et al. SPE 181353 Best Practices and Lessons Learned From More Than 1,000 Treatments: Revival of Mature Fields by Hydraulic Fracturing in Khalda Ridge, Egypt’s Western Desert by Mohamed Salah, Khalda Petroleum Company, et al. SPE 184840 Innovative Diversion Technology Ensures Uniform Stimulation Treatments and Enhances Gas Production: Examples From Carbonate and Sandstone Reservoirs by Zillur Rahim, Saudi Aramco, et al.

Identification of natural fractures using resistive image logs, fractal dimension and support vector machines

The purpose of this research is to apply a new approach to identify natural fractures in wells in a hydrocarbon reservoir using resistive image logs, fractal dimension and support vector machines (SVMs). The stratigraphic sequence investigated by each well is composed of Cretaceous calcareous rocks from the Catatumbo Basin, Colombia. The box counting method was applied to image logs in order to generate a curve representing variations of fractal dimension in these images throughout each well. The arithmetic mean of fractal dimension showed values ranging from 1,70 to 1,72 at the mineralized fracture intervals, and from 1,72 to 1,76 at the open fracture intervals. Morphological classification between open and mineralized natural fractures is performed using corelogs integration in a pilot well. Fractal dimension of images along with gamma rays and resistivity logs were employed as the input dataset of a SVM model identifying intervals with natural open fractures automatically, shortly after logs acquisition and previous to its interpretation by specialists. Although final results were affected by borehole conditions and logs quality, the SVM model showedaccuracy between 72,3% and 82,2% in 5 wells evaluated in the studied field.