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Shumway, Martin (Locus Bio-Energy Solutions) | McGonagle, Ryan (Locus Bio-Energy Solutions) | Nerris, Anthony (Locus Bio-Energy Solutions) | Aguiar, Janaina I.S. (Locus Bio-Energy Solutions) | Mahmoudkhani, Amir (Locus Bio-Energy Solutions) | Jacobs, D. Marc (Penneco Oil Company)
Abstract Legacy oil production from Appalachian basin has been in a decline mode since 2013. With more than 80% of wells producing less than 15 bbl/day, there is a growing interest in economically and environmentally viable options for well stimulation treatments. Analysis of formation mineralogy and reservoir fluids along with history of well interventions indicated formation damage in many wells due precipitation of organics and a change in wettability being partially responsible for production decline rates in excess of forecasts. The development and properties of a novel cost-effective biosurfactant based well-stimulation fluid are described here along lessons learned from several field trials in wells completed in the Upper Devonian Bradford Group. This group of 74 wells, completed in siltstone and sandstone reservoirs were presenting more than 12 well failures annually across the field, which was attributed to the accumulation of organic deposits in the tubulars. Based on these cases, batch stimulation treatments using a novel fluid comprising biosurfactants were proposed and implemented field wide. The treatments effectively removed organic deposits, changed formation wettability from oil to water wet and resulted in a sustained oil production increase. Well failures were significantly reduced as a result of this program and the group of 74 wells did not have a paraffin-related well failure for 18 months. Results from this program demonstrates the efficiency of the green well stimulation fluids in mitigating formation damage, reducing organics deposition and in increasing oil production as a promising method to stimulate tight formations.
Lazutkin, Dmitry Mikhailovich (LLC Gazpromneft – Technology Partnerships) | Bukov, Oleg Vladimirovich (LLC Gazpromneft – Technology Partnerships) | Kashapov, Denis Vagizovich (Federal State Budgetary Educational Institution of Higher Education Ufa State Petroleum Technological University USPTU) | Drobot, Albina Viktorovna (GeoSplit LLC) | Stepanova, Maria Alexandrovna (GeoSplit LLC) | Saprykina, Ksenia Mikhailovna (GeoSplit LLC)
Abstract New geological structures – displaced blocks of salt diapirs’ overburden – were identified in the axial part of the Dnieper-Donets basin (DDB) beside one of the largest salt domes due to modern high-precision gravity and magnetic surveys and their joint 3D inversion with seismic and well log data. Superposition of gravity lineaments and wells penetrating Middle and Lower Carboniferous below Permian and Upper Carboniferous sediments in proximity to salt allowed to propose halokinetic model salt overburden displacement, assuming Upper Carboniferous reactivation. Analogy with rafts and carapaces of the Gulf of Mexico is considered in terms of magnitude of salt-induced deformations. Density of Carboniferous rocks within the displaced flaps evidence a high probability of hydrocarbon saturation. Possible traps include uplifted parts of the overturned flaps, abutting Upper Carboniferous reservoirs, and underlying Carboniferous sequence. Play elements are analyzed using analogues from the Dnieper-Donets basin and the Gulf of Mexico. Hydrocarbon reserves of the overturned flaps within the study area are estimated to exceed Q50 (Р50) = 150 million cubic meters of oil equivalent.
Abstract Rechitsa multi-play oilfield is located within the Rechitsko-Vishanskaya subregional area of local uplifts of the Rechitsko-Vishanskaya tectonic stage of the Northern structural zone of the Pripyat Trough in the Republic of Belarus. Since 2014, Production Association Belorusneft has been conducting integrated research to study oil bearing capacity of sediments within rock Units I-III, which were previously considered to have no potential. Since then, the lithological and petrophysical, pyrolytic, and geomechanical features of the structure of these sediments have been studied. The research has confirmed the initial hypothesis that the studied sediments are unconventional reservoirs with source-rock genesis and contain hydrocarbons both of their own genesis and those which migrated from other rocks. The results of drilling and completion of horizontal exploration wells with multi-stage hydraulic fracturing confirmed the potential for obtaining commercial oil from the sediments of the unconventional reservoirs. At the same time, there were doubts about the optimal placement of the horizontal wells, the choice of completion strategy, and if the well performance lived up to the actual maximum potential of these sediments. The paper sums up the main results of implementing an integrated program for studying unconventional reservoirs of the Rechitsa oilfield, as well as of drilling and operating production wells to date.
Nashaat, Michael (Schlumberger) | Kolivand, Hassan (Schlumberger) | Zhiyenkulov, Murat (Schlumberger) | Seilov, Yerlan (Schlumberger) | Ghorayeb, Kassem (Schlumberger) | Shah, Abdur Rahman (Schlumberger) | Madatov, Roman (Schlumberger) | Grytsai, Svetlana (Ukrgazvydobuvannya) | Filatov, Viacheslav (Ukrgazvydobuvannya)
Abstract Skhidno-Poltavske Field is a Ukrainian gas field producing mostly from commingled wells. These commingled wells have no information about the production split and the pressure data measured for each formation separately. This was one of the main challenges to study the field and understand the potential of each individual formation. Many wells were hydraulically fractured (HF) and showed a wide range of production and pressure performance after the stimulation. Six of these HF wells showed atypical pressure and production behavior after the HF compared to the rest of the wells. The main challenge in the reservoir simulation study was to understand whether these HFs reached isolated lateral segments of the same producing zones or accessed other reservoir zones by/due to vertical propagation of the hydraulic fracture plane. Understanding the pressure and production performance of these wells and comparing them to the other wells was the key to revealing their behavior. This was integrated with the petrophysical data to understand the potential formations and the uncertainty range of their properties. The geomodeling was the destination to translate these uncertainties into different realizations that were all dynamically tested to generate the most probable realization. The integration between different domains resulted in unlocking an overlooked productive zone that was out of consideration. This increased the reserves of this field and extended its life. One of the study recommendations was to test and develop this formation through perforating the existing wells or drilling new wells targeting the overlooked productive zone.
Abstract We investigated numerically, the fracturing process for an infill multi-fracture horizontal well (MFHW) using the indirect boundary element method. Our code initially involved the constant 2D displacement discontinuity method (DDM), the higher-order 2D HDDM, and the 2D HDDM+ (involving square root tip elements) numerical schemes, all of which were validated against the analytical solution of Sneddon and Elliot (1946). The improved accuracy and computational efficiency obtained using the 2D HDDM and 2D HDDM+ numerical schemes led to further enhancement of the simulator by the introduction of higher-order elements in the 3D space. To the authors’ knowledge, this is the first application of the higher-order 3D HDDM to hydraulic fracture modeling since the original development of the method by Shou et al. (1997). The proposed method results in a more accurate estimation of the fracture width than the standard constant 3D DDM method, while preserving the same number of degrees of freedom. Our 3D HDDM method can neglect, without loss of accuracy, the dip-slip shear stress and the displacement components, thus improving the computational efficiency of the method. The associated fluid mechanics accounts for the pressure drop along the wellbore and across perforations to accurately predict the pressure and fluid flow rate distribution within each fracture. The nonlinear fluid mechanics equations were discretized by the finite difference method and iteratively coupled with the simplified 3D-DDM. The developed numerical scheme was validated against the Perkins-Kern-Nordgren (PKN) (Perkins and Kern, 1961; Nordgren, 1972) and Khristianovic-Geertsma-de Klerk (KGD) (Khristianovich and Zheltov, 1955; Geertsma and de Klerk, 1969) analytical models. We adopted the analytical solution of Economides and Nolte (2000) that depends on the local DDM results to obtain the fracture width distribution across multiple reservoir layers. Additionally, our simulator implements the fracture height growth methodology suggested by Li (2019). We conducted simulation studies of non-planar propagation of five simultaneously-induced fractures with variable spacing. Our simulator accurately predicts the fluid flow, pressure, and width distribution within each fracture, and can be an effective tool in the decision-making process of fracturing design in unconventional reservoirs.
Abstract The objective of this paper is to investigate how to acquire fracture closure pressure data accurately and cost-effectively in shale development activities. If the injection volume is small during a hydraulic fracturing job, it is a common practice to consider the ISIP (Instantaneous Shut-In Pressure) as a proxy of fracture closure pressure, which generally requires a long falloff period to evaluate. However, ISIP should consist of variable parameters such as the original closure pressure, net pressure, stress shadow effect, and mid-field fracture complexity. In this paper, we introduce the consecutive DFITs (Diagnostic Fracture Injection Test) approach. Closure pressure is evaluated by falloff pressure analysis after a micro fracturing injection operation, and pore pressure could also be evaluated if the falloff period is long enough. This micro fracturing operation is generally called DFIT. In order to evaluate how the ISIP, closure pressure, and pore pressure change from stage to stage, we performed DFITs consecutively at the sequential hydraulic fracturing stages in a horizontal well drilled in the Eagle Ford shale. The consecutive DFITs revealed that the ISIP gradually increased up to certain level from fracturing stage to stage as expected. However, the observed closure pressure was almost constant in the sequential stages, which was against our expectations. In addition, the evaluated pore pressure was also almost constant. Initially we expected that closure pressure would increase because of the uplift due to the stress shadow effect. Since the consecutive DFITs showed the same closure pressure in each stage, we concluded that stress uplift could disappear before the fracture closure in next stage or that the stress shadow had little impact on the closure pressure and the pore pressure in next stage under the current fracture design. On the other hand, the ISIP could be affected by the stress shadow in the short term or by the mid-field fracture complexity becoming higher than the previous stage. The correlation between the ISIP and the closure pressure was established with these consecutive DFITs results. Although the gap between the ISIP and closure pressure varies from stage to stage, it was confirmed that the correlation, with some uncertainties, could be used to estimate the closure pressure within an acceptable range. This paper presents the Eagle Ford case study, which confirmed how accurately ISIP can determine closure pressure considering multiple factors. There are hydraulic fracturing operations in huge number of horizontal wells in the shale development. Therefore, the correlation built by consecutive DFITs is useful because that correlation can provide operators with the confidence to optimize the completion design based on the ISIP which can be obtained at a low cost.
Li, Guoxin (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing) | Tian, Jun (Petrochina Exploration & Production Company) | Duan, Xiaowen (Tarim Oilfield Company, Petrochina) | Yang, Haijun (Petrochina Exploration & Production Company) | Tang, Yongliang (Tarim Oilfield Company, Petrochina) | Bi, Haibin (Tarim Oilfield Company, Petrochina) | Zhang, Cehngze (Petrochina Research Institute of Petroleum Exploration & Development) | Xian, Chenggang (Tarim Oilfield Company, Petrochina) | Liu, He (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing)
Abstract Located in Kelasu Structural Belt in northern Tarim Basin, China, Kelasu Gas Field has mainly pre-salt steep structures in the exploration targets of Cretaceous Bashijiqike and Baxigai Formations. The reservoirs have burial depth ranging from 6000m to 8000m and thickness ranging from 200m to 320m. The formation pressure is 150 MPa and the formation temperature is 190 °C. The reservoirs are typical tight sandstone gas reservoirs with matrix sandstone permeability ranging from 0.001mD to 0.1mD and the porosity ranging from 2% to 8%. The gas reservoirs are very serious in heterogeneity, with fault systems well developed. The distribution of water bodies is complex, and in some of the reservoirs, water invasion occurred fast at the early stage of development, which have serious influence on gas reservoir recovery. Through years of technical study and deepening understanding of geological characteristics and production performance of gas reservoirs, it has been made clear that the main factors affecting the efficient and economic development of the gas reservoirs are structural style, fault system and water body distribution. Laboratory displacement experiments and numerical simulation about differentiated techniques such as well patterns, well types, multi-stage hydraulic fracturing design and implementation, gas production rate have been carried out to explore the applicable measures for enhancement of recovery efficiency of tight sandstone gas reservoir under high temperature and ultra-high-pressure conditions. The research results show that the recovery efficiency of the tight gas reservoir has been increased by 10%-15% because of optimum selection of uniform well distribution or Z-shaped well pattern, developed well types with combination of vertical wells, highly deviated wells and horizontal wells, and temporary soft layers plugging and mechanical hard layered fracture network stimulation technology, implementation of annular pressure control and five-sphere integrated production management and control technology including "barrier maintenance, real-time monitoring, anomaly diagnosis, risk assessment and classification administration" to accelerate the fulfillment of fit-for-purpose wellbore life-cycle management and water prevention and sand control measures, and application of different technical strategies including differential gas production rate, etc.
Hegazy, Amr (General Petroleum Company) | Abdel Hakim, Emad (General Petroleum Company) | Farouk, Mohamed (General Petroleum Company) | Badran, Hesham (General Petroleum Company) | Barghash, Omar (Schlumberger) | Saleh, Khaled (Schlumberger)
Abstract One of the challenges when performing hydraulic fracturing is treating reservoirs that are close to a water-bearing zone. Unfortunately, uncontrolled fracture height growth adversely affects many treatments and often increases the probability of water influx. This risk of fracture growth into the water zone eradicates the chances of applying hydraulic fracturing treatment to enhance well productivity, hence diminishing further production and more recoverable reserves. Therefore, involving hydraulic fracturing in such an environment is extremely challenging and demands proper design and execution. This paper includes a field example from the Eastern Desert, Egypt, in which an artificial barrier (referred to as a "settle frac") is established to limit height growth into the underlying water zone and confine the fracture geometry to the pay zone to increase fracture length in a tight oil reservoir, thereby increasing dimensionless fracture conductivity. The productive pay zone of the reservoir has a net pay thickness of 5 m and has very low permeability that ranges from 0.1 to 10 md. The proximity of the water zone to the hydrocarbon-producing zone varies from 5 to 10 m, with the absence of any stress barriers. The challenge in these conditions was to enclose the fracture height in the producing zone and prevent the fracture from propagating into the underlying water zone. This paper describes the workflow followed in a pilot test of a dual hydraulic fracturing technique, from candidate selection to the post-treatment evaluation of the job. The work proved the importance of after-closure analysis (ACA) to obtain reservoir properties (i.e., initial reservoir pressure, Pi, and permeability, K) that match core analysis and formation tester (FT) data for a better understanding of the tight resources and optimizing hydraulic fracturing design. In addition, the work demonstrated the potency of the artificial barrier technique. This technique puts an artificial proppant barrier below the pay zone, close to the water-oil contact, formed by a low-viscosity fluid with high breaker loading and a proppant to create enough length and settled height to set up high resistance to fluid movement, thus limiting the vertical height growth of fractures. Using a smaller proppant size in the settle frac aids in reducing leakoff and in making the fracture longer inside the pay zone during the subsequent main treatment. The results of the artificial barrier technique indicate a 50-fold increase in production with no water production with 3 months payback time of the investment. The results likewise reinforce the potency ofthe artificial barrier technique with a smaller proppant size. The application of this technique and understanding the reservoir flow properties (Pi, K), mechanical properties (σhmin), and the in-situ stress of the adjacent layers unlocked the reserve of 2 MMstb (P50) in tight oil sand, and it will be part of an optimized field development plan to enhance the estimated ultimate recovery (EUR) of the field and consequently net present value (NPV) for incremental investment in the field. This paper shows the effect of employing the technique of placement of artificial barriers to curb fracture height growth. This novel technique facilitated the better development of this tight oil reservoir in the Eastern Desert fields.
Ibrahim, Mazher (Shear Frac Group LLC) | Sinkey, Matt (Shear Frac Group LLC) | Johnston, Thomas (Shear Frac Group LLC) | Marouf, Shabnam (Shear Frac Group LLC) | Noynay, John (Shear Frac Group LLC) | Becerril, Joseph (Shear Frac Group LLC)
Abstract Hydraulic fractures created during completion operations are assumed to produce back to the original well. While multi-well pad completions increase efficiencies, it complicates fracture connectivity between wells. The proximity of newly completed wells to a pre-existing producing well suggests a depleted zone that can "steal" fracture surface area. Correlations between real-time shear fracture measurements and post-stage Pressure Transient Analysis (PTA) can shed light on the fracture surface area connected to the original well vs. fracture surface area "stolen" by offset wells. During hydraulic fracturing operations, shear fractures per slurry barrel are measured on the active stage. The connected fracture surface area is then calculated using the end of stage fall-off pressure data via PTA. This allows for the correlation of the fracture surface area created and the fracture surface area connected back to the original stage. Variations off a straight-line correlation suggest interactions with offset wells. For example, when fracture interaction with an offset depleted zone is present, PTA will calculate an extremely high fracture surface area when compared to the number of fractures created during the active stage. This reduces the effective production as the area created is not able to produce back to the original well. This paper presents a new real-time method to estimate the stage-to-stage interference and well-to-well interference and their implications on completions efficiency. This paper also presents a solution to minimize frac hits between parent and child well based on generated fracture surface area to improve a pad's Estimated Ultimate Recovery (EUR). This is supported by a case history which shows a positive correlation between the created fracture surface area and its connectivity back to the wellbore. The new method does not require any well surveillance compared with existing methods and does not incur extra cost to operator.
Ding, Yanyan (Engineering Technology Research Institute of Xinjiang Oilfield Company, PetroChina) | Liang, Yu (Southwest Geophysical Research Institute of BGP, CNPC) | Zhao, Tingfeng (Engineering Technology Research Institute of Xinjiang Oilfield Company, PetroChina) | Ma, Mingwei (Engineering Technology Research Institute of Xinjiang Oilfield Company, PetroChina) | Huang, Xingning (Engineering Technology Research Institute of Xinjiang Oilfield Company, formerly PetroChina)
Abstract Shale reservoirs are characterized by low oil and gas abundance, poor permeability, lower natural production capacity than the lower limit of conventional oil production, and the reservoir pressure decreasing rapidly. At present, for the development of such low-porosity, low-permeability resources, horizontal well drilling and hydraulic fracturing technologies are widely used, relying on long sections of horizontal wells in the reservoir, and the hydraulic fracture formed by wellbore stimulation as an "underground highway" for the flow of oil and gas from the deep reservoir to the wellbore. The combination of these two techniques can significantly increase the availability of hydrocarbon resources in the reservoir. Multi-stage hydraulic fracturing for horizontal wells is the crucial technology to achieve efficient recovery of shale oil. The results of downhole imaging, distributed fiber-optic temperature and acoustic monitoring in the field indicate that there are apparent non-uniform fracture propagation of each cluster during the fracturing process. Related research results also indicate that factors such as non-homogeneity of the reservoir and stress interference from multiple fracture expansion are the leading causes of the non-uniform expansion of hydraulic fractures. Therefore, how to make each fractured section expand equally and improve the coverage of fractures in the horizontal well section can be studied by a numerical simulation method, based on the fundamental theories of elasticity and fracture mechanics. The simulation results are consistent with the micro-seismic fracture monitoring results; this has obvious significance for accelerating the development of difficult-to-use oil and gas resources and securing the supply.