Fracturing Height Growth Restriction Technique Successfully Extended into Horizontal Wells in Ostracod Formation

The Ostracod formation in the Awali brownfield is an extremely challenging layer to develop because the tight carbonate rock is interbedded with shaly streaks and because of the presence of a nearby water-bearing zone. Although the Ostracod formation has been in development since 1960, oil recovery has not yet reached 5% because past stimulation attempts experienced rapid production decline. The current project incorporated aggressive fracture design coupled with a unique height growth control (HGC) workflow, improving the development of Ostracod reserves. The HGC technology is a combination of an engineering workflow supported by geomechanical modeling and an advanced simulator of in-situ kinetics and materials transport to model the placement of a customized, impermeable mixture of particles that will restrict fracture growth. The optimized treatment design included injections of the HGC mixture prior to the main fracturing treatment. This injection was done with a nonviscous fluid to improve settling to create an artificial barrier. After the success of a trial campaign in vertical wells, the technique was adjusted for the horizontal wellbores. The high clay content within the Ostracod layers creates a significant challenge for successful stimulation. The high clay content prevents successful acid fracturing and leads to severe embedment with conventional proppant fracturing designs. We introduced a new approach to stimulate this formation with an aggressive tip-screenout design incorporating a large volume of 12/20-mesh proppant to obtain greater fracture width and conductivity, resulting in a significant and sustained oil production gain. The carefully designed HGC technique was efficient in avoiding fracture breakthrough into the nearby water zone, enabling treatments of up to 450,000 lbm to be successfully contained above a 20-ft-thick shaly barrier with small horizontal stress contrast. Independent measurements proved that the fracture height was successfully contained. This trial campaign in vertical wells proved that the combination of aggressive, large fracture designs with the HGC method could help unlock the Ostracod’s potential. Three horizontal wells were drilled and simulated, each with four stages of adjusted HGC technique to verify if this aggressive method was applicable to challenging sand admittance in case of transverse fractures. This rare implementation of HGC mixtures in horizontal wells showed operational success and proof of fracture containment based on pressure signatures and production monitoring. The applied HGC technique was modified with additional injections and improved by advanced modeling that only recently became available. These contributed to a significant increase of treatment volume, making the jobs placed in the Ostracod some of the world’s largest utilizing HGC techniques. The experience gained in this project can be of a paramount value to any project dealing with hydraulic fracturing near a water formation with insufficient or uncertain stress barriers.

Experimental Study on Fracturing Fracture Deformation Mechanism of Shale Reservoir

After large-scale sand fracturing of horizontal wells in shale gas reservoir, fracturing fractures will deform in the production process. However, fracture deformation will lead to the decrease in fracture conductivity and then cause the decrease of gas well productivity. Therefore, in order to evaluate the fracturing fracture deformation mechanism of shale reservoirs, the shale proppant-supported fracture deformation evaluation experiments were carried out under different proppant types, particle sizes, sanding concentrations, and closure pressure conditions, respectively, and the variation curves of fracture width was calculated by a stereomicroscope under different experimental conditions. Then based on the experimental results, the fracture sensitivity factors and fracture deformation mechanism were analyzed, and the deformation mechanisms of fracturing fractures affected by proppant embedding and crushing were studied emphatically. The analysis results of fracture sensitivity factors indicate that the larger the particle size and hardness of proppant, the lower the sand concentration, proppant embedded on the shale rock surface. Moreover, the deeper the proppant is embedded, the faster the fracture conductivity decreases. In addition, the greater the closure pressure, the more serious is the proppant embedment, and the faster the fracture width decreases. The analysis results of fracture deformation mechanism show that, on the on hand, under variable closure pressure, the proppant with larger hardness and larger particle size is used for fracturing, and the proppant embedded in the fracture surface is the main cause of fracture deformation. However, if only the sand concentration of the proppant in the fracture is changed, the fracture deformation is jointly dominated by the embedding and crushing of the proppant. On the other hand, under constant closure pressure, the main mechanism of fracture deformation is that the proppant is embedded into the fracture surface when the closure pressure is low, but if the closure pressure is high, the main mechanism of fracture deformation is the crushing and compaction of proppant.

Complex Stimulation Approach to Low-Temperature Carbonate Formation Revitalizes Bahrain Brownfield

Carbonate formations often require stimulation treatments to be developed economically. Sometimes, proppant fracturing yields better results than acid stimulation. Carbonates are seldom stimulated with large-mesh-size proppants due to admittance issues caused by fissures and high Young’s modulus and narrow fracture width. The Magwa formation of Bahrain’s Awali brownfield is a rare case in which large treatments using 12/20-mesh proppant were successful after the more than 50 years of field development. To achieve success, a complex approach was required during preparation and execution of the hydraulic fracturing campaign. During the first phase, the main challenges that restricted achieving full production potential in previous stimulation attempts (both acid and proppant fracturing) were identified. Fines migration and shale instability were addressed during advanced core testing. Tests for embedment were conducted, and a full suite of logs was obtained to improve geomechanical modeling. In addition, a target was set to maximize fracture propped length to address the need for maximum reservoir contact in the tight Magwa reservoir and to maximize fracture width and conductivity. Sufficient fracture width in the shallow oil formation was required to withstand embedment. Sufficient conductivity was required to clean out the fracture under low-temperature conditions (124°F) and to minimize drawdown along the fracture considering the relatively low energy of the formation (pore pressure less than 1,000 psi). Understanding the fracture dimensions was critical to optimize the design. Independent measurement using high-resolution temperature logging and advanced sonic anisotropy measurements after fracturing helped to quantify fracture height. As a result of the applied comprehensive workflow, 18 wells were successfully stimulated, including three horizontal wellbores with multistage fracturing - achieving effective fracture half-lengths of 450-to 500-ft. Oil production from the wells exceeded expectations and more than doubled the results of all the previous attempts. Production decline rates were also less pronounced due to achieved fracture length and the ability to produce more reservoir compartments. The increase in oil recovery is due to the more uniform drainage systems enabled by the conductive fractures. The application of new and advanced techniques taken from several disciplines enabled successful propped fracture stimulation of a fractured carbonate formation. Extensive laboratory research and independent geometry measurements yielded significant fracture optimization and resulted in a step-change in well productivity. The techniques and lessons learned will be of benefit to engineers dealing with shallow carbonate reservoirs around the world.

Zipper Fracturing of Horizontal Cluster Wells: Game Changing Unconventional Fracturing in UAE

Following the increase in demand for natural gas production in the United Arab Emirates (UAE), unconventional hydraulic fracturing in the country has grown exponentially and with it the demand for new technology and efficiency to fast-track the process from fracturing to production. Diyab field has historically been a challenging field for fracturing given the high-pressure/high-temperature (HP/HT) conditions, presence of H2S, and the strike-slip to thrust faulting conditions. Meanwhile, operational efficiency is necessary for economic development of this shale gas reservoir. Hence "zipper fracturing" was introduced in UAE with modern technologies to enable both operational efficiency and reservoir stimulation performance. The introduction of zipper fracturing in UAE is considered a game changer as it shifted the focus from single-well fracturing to multiple well pads that allow for fracturing to take place in one well while the adjacent well is undergoing a pumpdown plug-and-perf operation using wireline. The overall setup of the zipper surface manifold allowed for faster transitions between the two wells; hence, it also rendered using large storage tanks a viable option since the turnover between stages would be short. Thus, two large modular tanks were installed and utilised to allow 160,000 bbl of water storage on site. Similarly, the use of high-viscosity friction reducer (HVFR) has directly replaced the common friction reducer additive or guar-based gel for shale gas operation. HVFR provides higher viscosity to carry larger proppant concentrations without the reservoir damage, and the flexibility and simplicity of optimizing fluid viscosity on-the-fly to ensure adequate fracture width and balance near-wellbore fracture complexity. Fully utilizing dissolvable fracture plugs was also applied to mitigate the risk of casing deformation and the subsequent difficulty of milling plugs after the fracturing treatment. Furthermore, fracture and completion design based on geologic modelling helped reduce risk of interaction between the hydraulic fractures and geologic abnormalities. With the application of advanced logistical planning, personnel proficiency, the zipper operation field process, clustered fracture placement, and the pump-down plug-and-perforation operation, the speed of fracturing reached a maximum of 4.5 stages per day, completing 67 stages in total between two wells placing nearly 27 million lbm of proppant across Hanifa formation. The maximum proppant per stage achieved was 606,000 lbm. The novelty of this project lies in the first-time application of zipper fracturing, as well as the first application of dry HVFR fracturing fluid and dissolvable fracturing plugs in UAE. These introductions helped in improving the overall efficiency of hydraulic fracturing in one of UAE's most challenging unconventional basins in the country, which is quickly demanding quicker well turnovers from fracturing to production.

Pumping Schedule Optimization in Acid Fracturing Treatment by Unified Fracture Design

Acid fracturing simulation has been widely used to improve well performance in carbonate reservoirs. In this study, a computational method is presented to optimize acid fracturing treatments. First, fracture geometry parameters are calculated using unified fracture design methods. Then, the controllable design parameters are iterated till the fracture geometry parameters reach their optimal values. The results show higher flow rates are required to achieve optimal fracture geometry parameters with larger acid volumes. Detailed sensitivity analyses are performed on controllable and reservoir parameters. It shows that higher flow rates should be applied for fluids with lower viscosity. Straight acid reaches optimal conditions at higher flow rates and lower volumes. These conditions for retarded acids appear to be only at lower flow rates and higher volumes. The study of the acid concentration for gelled acids shows that both flow rate and volume increase as the concentration increases. For the formation with lower permeability, a higher flow rate is required to achieve the desired larger fracture half-length and smaller fracture width. Further investigations also show that the formation with higher Young’s modulus requires decreasing the acid volume and increasing the optimal flow rate, while the formation with higher closure stress requires increasing the acid volume and decreasing the flow rate.

Natural Fractures Characteristics of the Carboniferous Volcanic Reservoir in Northwestern Margin of Junggar Basin

Research on the regional fracture’s development is important for reservoir fracturing. This paper takes the Carboniferous volcanic reservoir in the northwestern margin of Junggar Basin as the research object. Based on understanding the regional tectonic faults and geological characteristics, the parameter characteristics of natural fractures are analyzed using imaging logging data, and natural fractures distribution characteristics are compared with regional faults and in-situ stresses, as well as the pattern of natural fractures formation is revealed. The results indicated that: (1) The Carboniferous in the northwestern margin of Junggar Basin area mainly develops 3 NE-trending reverse faults. The reservoir type is pore-fracture dual media type, with an average porosity of 7.64% and an average permeability of 1.16mD, which belongs to the medium-porosity and ultra-low permeability reservoir; (2) Reservoir fractures are generally well developed. High-conductivity fractures and high-resistance fractures coexist, but high-conductivity fractures are the main ones. The fracture width is between 0.053 and 0.23 mm, and the fracture density is between 0.5 and 1.68 strips/m. The length is between 0.54-1.88m, the fracture porosity is between 3.4×10-5-41×10-5, and the dominant fracture trend is mainly NE50°-NE80°; (3) The direction of the maximum horizontal in-situ stress of the reservoir is mainly NE30°-NE60°, in the direction of NEE, it differs from fracture strike by 10°-50°, and roughly the same as the strike of the three reverse faults.

The Responses of Injection Pressure and Fracture Width during Height Extension in Sand-Mud Interbed Reservoirs in the Dongsheng Gas Field

The Dongsheng gas field is characterized by low porosity and low permeability. Its principal producing reservoir is the H-1 zone, belonging to the Lower Shihezi Formation. Sand is the main lithology in the H-1 zone, while mud interlayers are also well developed in a vertical direction. As a result, the reservoir is a sand-mud interbed, which brings difficulty to fracture height extension. In order to understand the process of fracture height growth in a sand-mud interbed reservoir and obtain the responses of injection pressure and fracture width during a hydraulic fracturing, a hydromechanical-coupled model is established. Mud interlayers are fully considered and a cohesive zone model is adopted to deal with fracture propagation. Numerical results show that the fracture extends quickly to the sand-mud interface after initiation and breaks through rather than propagating along the interfaces. Pressure and width both increase continuously when fracture propagates in the mud interlayer. High-viscosity and high-injection rates are helpful for the fracture to break through the mud interlayer, especially at an early period. When the mud interlayers are asymmetric, pressure and width fluctuate several times once fracture propagates inside and breaks through the mud interlayer. Perforations close to the thinner mud interlayer can increase the fracture width and reduce fracturing risks.

Study on Oil-water Two-phase Migration Mechanism of Low Permeability Fractured Core based on the Online NMR Testing

Understanding the dynamic migration mechanism of oil-water two-phase is the key to improve the effect of water injection development in low permeability fractured reservoir. Based on artificial fracturing of core and basic physical parameter testing, the online NMR displacement experiments of cores with different fracture widths are conducted to analyze the oil-water dynamic distribution characteristics and migration mechanisms. The experimental results show that when water breaks through at the outlet, oil volume in the small pores is basically unchanged. In the large pores it decreases to a certain extent, while in the fracture it decreases greatly. When the displacement is over, oil volume in the small pores still changes little, while it decreases greatly in the large pores, and it is almost zero in the fracture. With the decrease of fracture width, the recovery ratio when waterflooding front breaks through and the final recovery ratio after displacement increase gradually. The contribution proportion of recovery ratio in the fracture decreases as a whole, while in the large pores it increases gradually, and in the small pores it decreases slightly. The research results lay a foundation for the optimal design of fracture parameters and the adjustment of water injection development technology policy in low permeability fractured reservoir.

Tensile Failure and Fracture Width of Partially Permeable Wellbores with Applications in Lost Circulation Material Design

Summary Estimation of near-wellbore fracture widths remains central to designing the particle size distribution (PSD) and composition of lost circulation material (LCM) blends. Although elastic rock models are often used for this purpose, they fall short in capturing the substantial effect of pore fluid pressure on the fracture width. The problem is addressed in this paper by incorporating the poroelastic back stress in width estimation of axial fractures nearby an inclined wellbore. The poroelastic back stress is caused by a nonideal drilling fluid filter cake allowing for fluid pressure communication between the wellbore and pore space of the rock surrounding the wellbore. In this aspect, a proper definition of the filter-cake efficiency is made in terms of the wellbore pressure, far-field pore fluid pressure, and pore fluid pressure of the rock surrounding the wellbore. The value of this parameter is estimated from the standard drilling fluid filtration test results, as well as the formation rock permeability. The filter-cake efficiency is next used to develop the long-time, asymptotic analytical solution for the poroelastic stress of an inclined wellbore. By accounting for the obtained poroelastic back stress, an improved estimation of the wellbore tensile limit that depends on the filter-cake efficiency parameter is developed. For wellbore pressures beyond the wellbore tensile limit, the width of the near-wellbore fractures is estimated. The fracture width estimation is made through an analytical, dislocation-based fracture mechanics solution to the integral equation describing the nonlocal stress equilibrium along the fracture faces. The commonly practiced scheme for geometric design of LCM blends is enhanced by using the presented improvement in estimation of the near-wellbore fracture width. A case study is used to demonstrate the substantial effect of drilling fluid filtration properties and the resulting poroelastic back stress on the wellbore tensile limit, estimated fracture width, and consequently, composition of the recommended LCM blend.