Wei, Yunsheng (Research Institute of Petroleum Exploration and Development) | Wang, Junlei (Research Institute of Petroleum Exploration and Development) | Jia, Ailin (Research Institute of Petroleum Exploration and Development) | Qi, Yadong (Research Institute of Petroleum Exploration and Development) | Liu, Cheng (PetroChina Zhejiang Oilfield Company)
It is of great significance to optimize the design of multistage-fractured horizontal wells (MFHW) for increasing recoverable reserves. The main objective of this work is to provide a quantitative assessment of optimal decisions such as number of wells, number of fractures per well, mass of proppant and fracture dimensions. In this study, a rigorous performance simulation of multiwell pad is established to account for the interwell interference caused by varying-conductivity fractures connected to MFHW. Next, a semi-analytical approach is proposed to forecast the transient rate response and investigate the effect of fracture dimensions and completion parameters on estimated ultimate recovery (EUR). Finally, a systematic workflow that optimizes an overall economic objective is developed. The fracture design is posed as nested optimization, where the outer-optimization shell determines the number of MFHW and the number of fractures per MFHW, whereas the inner-optimization shell based on the time-dependent unified fracture design (UFD) involves the decisions on the optimal fracture dimensions.
Kindi, Ahmed (Petroleum Development Oman) | Shanfari, Abdul Aziz (Petroleum Development Oman) | Florez Chavez, Juan (Petroleum Development Oman) | Mufarraji, Ahmed (Petroleum Development Oman) | Barhi, Khalfan (Petroleum Development Oman) | Al-Yaqoubi, Mazin (Petroleum Development Oman) | Farsi, Shaima (Petroleum Development Oman)
Petroleum Development Oman (PDO) is currently exploring and developming a number of onshore unconventional deep gas fields for which hydraulic fracturing is playing a key role in proving the commerciality of such reserves. However, stimulating unconventional deep sandstone gas reservoirs with the conventional slick water or crosslinked polymer systems is associated with many challenges. While crosslinked systems frequently cause post-stimulation damage in tight formations (due to the high gel residues in the pores), slick water treatments are, in turn, associated with high surface treating pressures and low-carrying capacity for the high-strength proppants required to withstand the extreme stresses in the deep unconventional formations. In addition, the tightness and high capillary pressures characterizing unconventional reservoirs commonly lead to undesired post-fracturing results, including slow cleanout and poor productivity. The objective of this paper is to describe successful field trials using new fracturing strategy, which was deployed in deep unconventional sandstone gas wells in the Sultanate of Oman. Lineargel fracturing systems combined with high-strength ceramic proppant were utilized to unlock the gas from deep, highly stressed formations with porosity of 3-7% and permeability of 0.1-0.001
Dell'Aversana, Paolo (Eni SpA) | Servodio, Raffaele (Eni SpA) | Bottazzi, Franco (Eni SpA) | Carniani, Carlo (Eni SpA) | Gallino, Germana (Eni SpA) | Molaschi, Claudio (Eni SpA) | Sanasi, Carla (Eni SpA)
In this paper, we introduce a new technology permanently installed on the well completion and addressed to a real time reservoir fluid mapping through time-lapse electric/electromagnetic tomography while producing and/or injecting. Our technology consists of electrodes and coils installed on the casing/liner in the borehole/reservoir section of the well. We measure the variations of the electromagnetic fields caused by changes of the fluid distribution in a wide range of distances from the well, from few meters up to hundreds meters. The data acquired by our technology are processed and interpreted through an integrated software platform that combines 3D and 4D geophysical data inversion with a Machine Learning platform equipped with a complete suite of classification/prediction algorithms. Every time new data are acquired, they are fully integrated with the previous database, and used for decreasing the level of uncertainty about the dynamic model of the reservoir. In order to clarify the potential impact of such system on reservoir management, we apply this methodology to a synthetic data set. We discuss a simulation of a scenario where the waterfront approaches the wells during oil production. The goal of our test is to show how to combine our technology with Machine Learning to make robust predictions about the water table variations around the production wells.
Complex hydrocarbon distributions where reservoirs are filled by oil and gas phases with different densities and genetic types interfingering within a basin are a common phenomenon in Southeast Asia and are often attributed to vertical migration. Attempts to understanding the controlling factors of vertical hydrocarbon migration by modeling the hydrocarbon charging and entrapment history from two Cenozoic basins in Southeast Asia—West Java and the Madura Platform—are discussed.
A modified invasion percolation algorithm was used to simulate the secondary migration models, which follows the principle that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. Three-dimensional (3D) seismic data were used as the base grid for migration simulation to capture the effect of both structure and facies variations on fluid flow.
Two models, one from the West Java Basin (fault-bounded structure) and the East Java Basin (nonfault-bounded structure), are presented. For both cases, interfingering between oil and gas occurred, with most oils trapped within the lower formations, a mixture of oil and gas dominates the middle formations, and mostly gas in the upper formation. These vertical arrangements are possible because of the relatively weak formational seals within the basin. For vertically distributed reservoirs, oil is often trapped within the lower interval, and gas is trapped at the upper interval. For a basin dominated by a vertical migration regime, the potential risk for hydrocarbon lateral travel far away from the kitchen is high, thus increasing the potential risk of prospectivity away from the kitchen. Understanding factors that help control vertical migration also help geologists better understand hydrocarbon distributions within the basins.
Case studies during which modeling helped determine the factors that influenced vertical hydrocarbon migration and the resulting potential phase distribution prospectivity risks in the studied basins are discussed.
An abundant supply of low-cost local sands and their associated logistical advantages have incentivized operators over the last couple of years to use them in hydraulic fracturing treatments of unconventional reservoirs. Local sands are known for their low crush strength and high angularity and can contain other mineral particulates, besides quartz, compared to high-quality sands. This paper describes laboratory tests to demonstrate that low-quality sands, when treated with a binder, can generate stable, highly conductive channels within a simulated propped fracture, which could help maximize and also maintain production of hydrocarbons from the reservoir.
Laboratory experiments were conducted to evaluate the performance of local sands when used in aggregate structures, simulating proppant ridges or partial packs formed in a propped fracture. These aggregates were formed by coating sand grains with a binder and placing them in molds to be cured before testing. The sand aggregates were then placed in API conductivity cells to determine the effect of closure stresses on aggregate height, size expansion, binding agent concentrations, and conductivity measurements. Cyclic stress testing was also performed to evaluate the stability of the aggregate structure and conductivity retention of flow channels as the aggregate was subjected to varying stress loads.
The results obtained during this study indicate that the flow capacity of conductive channels prepared from proppant aggregates using local sands is comparable to those prepared using high-quality sand or high-strength manufactured proppant. Fines migration from proppant crushing within the aggregate was observed not to be a concern because sand grains connected and encapsulated by the binder helped lock the crushed sand together. Despite having diminishing permeability within the aggregates, flow capacity of solids-free channels between aggregate masses dominates flow through the propped fracture, making formation of proppant aggregates with high-quality sand or high-strength proppant (HSP) unnecessary.
This suggests that using local sands, despite their low crush resistance, during fracturing treatments can effectively enable well production by forming highly conductive voids or channels on top of the settled sand packs in the propped fractures in a shale reservoir.
Huang, Jiangshui (CNPC USA) | Gong, Wei (CNPC Chuanqing Drilling Engineering Company Ltd) | Lin, Lijun (CNPC USA) | Yin, Congbin (CNPC Chuanqing Drilling Engineering Company Ltd) | Liu, Fuchen (CNPC Engineering Technology R&D Company Ltd) | Zhou, Han (CNPC Chuanqing Drilling Engineering Company Ltd) | Bai, Litao (CNPC USA) | Song, Lulu (CNPC USA) | Yang, Zhengzhou (CNPC Engineering Technology R&D Company Ltd)
Tight oil reservoirs need stimulation in order to produce the trapped oil. The most common form of stimulation used by the oil and gas industry is hydraulic fracturing. Fracturing operations tend to create fractures including primary fractures and microfractures. The objective of this study is to develop a fracturing fluid which can be converted into microproppant, beads, and channelized-proppant as desired in-situ during a fracturing operation to enhance the hydraulic conductivity of the microfractures and the primary fractures, and simplify the hydraulic fracturing operation, where the channelized-proppant is defined as the pillars surrounded by channels.
Resin, curing agents, surfactants, and aqueous phase were mixed together to form O/W emulsion to serve as fracturing fluid. After curing process, resin and curing agent would react and form proppant in-situ. The parameters affect the proppant formation such as the curing temperatures, pressure, mixing strength, surfactant concentration, and size control additives were all studied and thus through controlling the parameters, microproppant, beads, and channelized-proppant can form in-situ as desired. The particle size distribution, sphericity, roundness, conductivity, acid solubility, and crush strength were tested.
Through controlling the experimental parameters and adding size control additives, fracturing fluid can be converted into microproppant, beads, and channelized-proppant as desired at a temperature from 30° C to 90° C. Almost 100% of the resin and the curing agents were converted into proppant with a specific density of 1.09g/ml. For the beads, both the sphericity and roundness are over 0.9, less than 2% fines were generated after being loaded to 15 kpsi, the acid solubility is 2.37%, and the conductivity of the beads of 20/40 mesh tested with proppant loading of 1 lb/ft2 at 4000 psi at room temperature was 227 mD-ft. For the microproppant, both the sphericity and roundness are close to 1 with d50 about 80 µm. Furthermore, channelized-proppant was formed in an artificial fracture with walls made of glass sheets. Thus, with the fracturing fluid developed, the conductivity of the well can be maximally optimized through the in-situ formation of channelized proppant and microproppant to keep the primary fractures and microfractures open respectively.
Acidizing and acid fracturing techniques are routinely used in two important formations in the marine regions of Mexico, the Jurassic and Cretaceous formations. These formations are naturally fractured carbonate and dolomite reservoirs having a permeability in the range of 0.19 to 22 mD, porosity from 2.8 to 6%, approximate bottomhole temperature (BHT) up to 177°C, pressure (BHP) of 10,374 psi, and a crude of 45° API. Using acid fracturing techniques helps improve the development of these assets. This paper shows the results of more than 40 acid fracturing operations performed in recent years.
Depending on the productivity evaluation, wells belonging to these assets are stimulated as part of the completion stage. Because of their low permeability, a common approach is to perform an acid fracturing operation. As a first evaluation, a minifrac test is executed to obtain the necessary data to calibrate the acid fracturing simulation model. After this step is performed, the acid fracturing design is evaluated. Generally, a sustained production acidizing technique is used for conductivity enhancement and closed-fracture acidizing is also included as a tailored treatment with an all seawater-based acidizing system.
For these operations, an average five-fold increase in oil production has been observed after treatment. In some cases wells in the completion stage, having no production before treatment, delivered up to 7000 BOPD after treatment. In these low-permeability assets, the post-fracturing response shows good results in general terms, increasing final conductivity in the near-wellbore area, and improving the production in these wells. The fracture gradient observed varies from 0.715 to 0.981 psi/ft with an average minimum stress of 13,670 psi. To perform the acid fracturing treatments, an average of 6400 hydraulic horsepower (HHP) must be available, with up to 13,400-psi surface pressure observed. As such, a stimulation vessel is necessary in all operations, applying a 26-bbl/min average pumping rate.
Globally, acid fracturing treatments are a common stimulation technique. This study shows that stimulating proper candidates in Mexico using acid fracturing significantly helps increase production, which may be relevant for the exploitation of new areas where fracturing has not been implemented.
Kidogawa, Ryosuke (INPEX Corporation) | Yoshida, Nozomu (INPEX Corporation) | Fuse, Kei (INPEX Corporation) | Morimoto, Yuta (INPEX Corporation) | Takatsu, Kyoichi (INPEX Corporation) | Yamamura, Keisuke (INPEX Corporation)
Productivity of multistage-fractured gas wells is possibly degraded by conductivity impairments and non-Darcy flow during long-term production. Such degradations are pronounced by flow convergence to short perforated intervals, while it is challenging to identify degraded stages for remediation. Moreover, remedial actions can be expensive under high-pressure and high-temperature (HP/HT) environment. A field case demonstrates successful application of re-perforation as a cost-effective way to mitigate the flow convergence by prioritizing targets with multi-rate production logging (PL) results.
This work presents theoretical investigations using numerical simulations and field execution of re-perforation for a well with six-stage fracturing treatments in a HP/HT volcanic gas reservoir onshore Japan. Apparent conductivity reduction was suspected during more than 15 years of production, and it was pronounced by non-Darcy flow effects associated with flow convergence to short perforated intervals. Multi-rate PL was employed to identify impaired stages by quantifying inflow performance relationship (IPR) of each stage under transient flow-after-flow testing. The impaired stages were re-perforated adding perforation intervals with wireline-conveyed perforators. Pre/post pressure build-up tests and post-job PL were used to validate productivity improvements.
Target zones for re-perforations were identified and prioritized with results of the multi-rate PL conducted. The stage IPRs were drawn, and relatively large non-Darcy effects were identified in three stages by shapes of the IPRs and/or decreasing inflow contributions as surface rate increased. Also, temperature log showed steep temperature change at bottom of the 4th stage; the fracture might propagate below the perforated interval. Ranges of production increment were estimated using a numerical model calibrated against the estimated stage IPRs. The estimated increment was in range of 15% to 30% with planned re-perforation program while its magnitude depended on connection between new perforations and existing fractures. Afterwards, re-perforation job was done, and, the gas rate was confirmed to be increased by 26% with the same well-head pressure after one month of production. The post-job PL was conducted three months after the re-perforation. The well's IPR was improved implying reduction of the non-Darcy effects. Results of pressure build-up tests also indicated reduction of skin factor. The stage IPRs were redrawn with the post-job PL, and they suggested clear improvements in two stages where screen-out occurred during fracturing treatments and a stage where significant non-Darcy effect was suspected.
The workflow and strategy in this paper can be applied for productivity restoration in a cost-effective way to multi-stage fractured gas wells with short perforated intervals and impaired apparent conductivity during long-term production. Especially, the interpreted results suggested effectiveness of the proposed approach for productivity improvement in stages where screenout occurs during fracturing treatments. Moreover, lessons learned on importance of careful test designs for PL were discussed because they are keys for success.
Zhao, Xing (China Zhenhua Oil Company Ltd.) | Wang, Hehua (China Zhenhua Oil Company Ltd.) | Lu, Lize (China Zhenhua Oil Company Ltd.) | Liu, Zhibin (Southwest Petroleum University) | He, Enjie (China Zhenhua Oil Company Ltd.)
For prediction of the post production of acid fracturing, a numerical method has been introduced in this paper. This prediction approach is developed by the dynamic differential modeling method for forecasting single well acid fracturing performance. In this study, the average production during 30 days and fracture geometry after acid fracturing were determined as predicted indices. Fifteen parameters were considered as influencing factors consisted of geological, reservoir and treatment parameters. The field data of predicted indices and influencing parameters were collected from the data of 7 acid-fractured wells in the XB oil field. The historical data was input into the dynamic differential model to establish and discretize the relation functions. Three target well were chosen and their corresponding influencing factors were used to calculate the predicted indices. The results showed that for the target wells, the modeling predicted indices were fairly close to the real numbers. This model is practical for the engineer in the field since the input parameter acquisition is accessible from the common oil field data. It could help the engineers to optimize the acid fracturing treatment design by correlating the scale of the treatment.
Zhang, Lufeng (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum at Beijing) | Zhou, Fujian (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum at Beijing) | Feng, Wei (Dipartimento di Geoscienze, Universita degli Studi di Padova) | Cheng, Jiaqi (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum at Beijing)
As proved from both experimental tests and field applications, diversion agents can effectively plug the previously artificial fractures or natural fractures to create reorientation fractures, which can improve diversion efficiency and stimulated reservoir volume (SRV). However, the temporary plugging mechanism and its influencing factors were still unclear.
In light of this, a fracture temporary plugging evaluation system was proposed by this study, which holds large fracture scale, and high pressure-bearing capability. Hence, this setup can meet the requirements of plugging tests. Moreover, in order to enhance the experimental accuracy, the 3D printing technique was introduced, which can reproduce the real surface morphology of acid-etched fracture. Based on the newly designed setup, some experiments were performed to study the plugging rules of fibers and the combination of fibers and particulates. Furthermore, the inner plugging mechanisms of the different cases were also analyzed.
Experimental results show that the pure fibers and the combination of fibers and particulates both can achieve favorable plugging effect. In addition, the plugging processes of pure fibers can be summaried as follows: 1) The carrier fluid with fibers flow into the fracture model and a small amount of fibers remain in the fracture. 2) Fibers begin to adhere to the fracture surface with a small fracture width. 3) The previously attached fibers capture the subsequently injected fibers to bridge plugging. 4) The bridging plugging extend to the entrance and eventually form a tight plugging zone. Furthermore, when the diameter of particulates is less than the half of fracture width, the plugging mechanism is similar as that of pure fibers. When the diameter of particulates is larger than the half of fracture width, the plugging mechanism is completely different from that of pure fibers. The big particulates will firstly be bridging and plugging at the location with a small fracture width.
This study reveals the temporary plugging mechanism of diversion agents within acid-etched fracture, which provides an insight of optimizing temporary plugging fracturing design.