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Journal of Petroleum Exploration and Production Technology
Journal Prestige (SJR): 0.344  Citation Impact (citeScore): 1 Number of Followers: 2  Open Access journalISSN (Print) 2190-0558 - ISSN (Online) 2190-0566 Published by SpringerOpen  [229 journals]
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- A review on application of nanoparticles for EOR purposes: history and
current challenges
Abstract: Abstract Applications of nanotechnology in several fields of petroleum industry, e.g., refinery, drilling and enhanced oil recovery (EOR), have attracted a lot of attention, recently. This research investigates the applications of nanoparticles in EOR process. The potential of various nanoparticles, in hybrid and bare forms for altering the state of wettability, reducing the interfacial tension (IFT), changing the viscosity and activation of other EOR mechanisms are studied based on recent findings. Focusing on EOR, hybrid applications of nanoparticles with surfactants, polymers, low-salinity phases and foams are discussed and their synergistic effects are evaluated. Also, activated EOR mechanisms are defined and specified. Since the stabilization of nanofluids in harsh conditions of reservoir is vital for EOR applications, different methods for stabilizing nanofluids through EOR procedures are reviewed. Besides, a discussion on different functional groups of NPs is represented. Later, an economic model for evaluation of EOR process is examined and “Hotelling” method as an appropriate model for investigation of economic aspects of EOR process is introduced in detail. The findings of this study can lead to better understanding of fundamental basis about efficiency of nanoparticles in EOR process, activated EOR mechanisms during application of nanoparticles, selection of appropriate nanoparticles, the methods of stabilizing and economic evaluation for EOR process with respect to costs and outcomes.
PubDate: 2023-04-01
- Laboratory study of plugging mechanism and seal integrity in fractured
formations using a new blend of lost circulation materials
Abstract: The problem of lost circulation occurred long during the drilling operation. Through induced and natural fractures, huge drilling fluid losses lead to higher operating expenses during the drilling. Historically, this problem was addressed with the help of the Lost Circulation Materials (LCMs). These materials are added to the drilling fluid to seal the fractures and increase fracture initiation or propagation pressure. Therefore, understanding the mechanisms of fracture sealing and the performance of the lost circulation materials is critical if the problem of lost circulation is to be mitigated effectively. Despite extensive advances in the last couple of decades, lost circulation materials used today still have disadvantages, such as damaging production zones, failing to seal large fractures, or plugging drilling tools. Here, we propose a new blend of smart expandable lost circulation material (LCM) to remotely control the expanding force and functionality of the injected LCM. This paper aimed to assess the performance of the selected LCMs (Mica, Wheat Straw, Oak Shell, and Sugarcane Bagasse Fiber or Canes) in water-based drilling fluids. The particle bridging of LCMs was investigated using particle bridging experiments in the laboratory. Moreover, we determined the particle size distribution of D50. The cell utilized in the sealing experiments had 1000- and 3000 micron fractures to mimic different size fractures in the formation. Fracture widths are predicted based on well-log data and adaptation of existing models in the desired oil field. The concentrations of LCMs in Mica, Wheat Straw, Oak Shell, and Sugarcane Bagasse Fiber (Canes) were (25, 50, and 80 ppb), (1.5, 2, 2.5 ppb), (3, 6, and 10 ppb), and (1.5, 2, 2.5 ppb), respectively. The results indicate that a combination of LCMs outperforms individual LCMs. When used individually, Oak Shells performed the highest, followed by Mica and Sugarcane Bagasse Fiber mixtures. Also, the Wheat Straw blend served the weakest lost circulation treatments. Finally, the combination applied in this investigation successfully sealed fractures up to 3 mm in diameter in the targeted oil field, which traditional LCM would be unable to do. Due to the abundance and low cost of these materials in the study area, they can be used to ensure successful plugging. Graphical
PubDate: 2023-04-01
- Assessment of foam generation and stabilization in the presence of crude
oil using a microfluidics system
Abstract: Abstract The use of foams is a promising technique to overcome gas mobility challenges in petroleum reservoirs. Foam reduces the gas mobility by increasing the gas apparent viscosity and reducing its relative permeability. A major challenge facing foam application in reservoirs is its long-term stability. Foam effectiveness and stability depends on several factors and will typically diminish over time due to degradation as well as the foam-rock-oil interactions. In this study, the effect of crude oil on CO2-foam stability and mobility will be investigated using in-house build microfluidics system developed for rapid prescreening of chemical formulations. Two-phase flow emulsification test (oil-surfactant solutions) and dynamic foam tests (in the absence and presence of crude oil) were conducted to perform a comparative assessment for different surfactant solutions. A microfluidics device was used to evaluate the foam strength in the presence and absence of crude oil. The assessment was conducted using five surfactant formulations and different oil fractions. The role of foam quality (volume of gas/total volume) on foam stability was also addressed in this study. The mobility reduction factor (MRF) for CO2-foam was measured in the absence and presence of crude oil using high salinity water and at elevated temperatures. The results indicated that foam stability has an inverse relationship with the amount of crude oil. Crude oil has a detrimental effect on foams, and foam stability decreased as the amount of crude oil was increased. Depending on the surfactant type, the existence of crude oil in porous media, even at very low concentrations of 5% can significantly impact the foam stability and strength. The oil can act as an antifoaming agent. It enters the thin aqueous film and destabilizes it. This resulted in a lower foam viscosity and less stable foams. Thus, the CO2 MRF dropped significantly in the presence of higher oil fractions. This study also demonstrated that in-house assembled microfluidics system allows for a rapid and cost-efficient screening of formulations.
PubDate: 2023-04-01
- Data-driven EUR for multistage hydraulically fractured wells in shale
formation using different machine learning methods
Abstract: Abstract This study proposes the use of different machine learning techniques to predict the estimated ultimate recovery (EUR) as a function of the hydraulic fracturing design. A set of data includes 200 well production data, and completion designs were collected from oil production wells in the Niobrara shale formation. The completion design parameters include the lateral length, the number of stages, the total injected proppant and slurry volumes, and the maximum treating pressure measured during the fracturing operations. The data set was randomly split into training and testing with a ratio of 75:25. Different machine learning methods were to predict EUR from the completion design including linear regression, random forest (RF), and decision tree (DT) in addition to gradient boosting regression (GBR). EUR prediction from the completion data showed a low accuracy. As result, an intermediate step of estimating the well IP30 (the initial well production rate for the first month) from the completion data was carried out; then, the IP30 and the completion design were used as input parameters to predict the EUR. The linear regression showed some linear relationship between the output and the inputs, where the EUR can be predicted with a linear relationship with an R-value of 0.84. In addition, a linear correlation was developed based on the linear regression model. Moreover, the other ML tools including RF, DT, and GBR presented high accuracy of EUR prediction with correlation coefficient (R) values between actual and predicted EUR from the ML model higher than 0.9. This study provides ML application with an empirical correlation to predict the EUR from the completion design parameters at an early time without the need for complex numerical simulation analysis. Unlike the available empirical DCA models that require several months of production to build a sound prediction of EUR, the main advantage of the developed models in this study is that it requires only an initial flow rate along with the completion design to predict EUR with high certainty.
PubDate: 2023-04-01
- Discrete fracture modeling by integrating image logs, seismic attributes,
and production data: a case study from Ilam and Sarvak Formations, Danan
Oilfield, southwest of Iran
Abstract: Abstract Understanding the fracture patterns of hydrocarbon reservoirs is vital in the Zagros area of southwest of Iran as they are strongly affected by the collision of the Arabian and Iranian plates. It is essential to evaluate both primary and secondary (fracture) porosity and permeability to understand the fluid dynamics of the reservoirs. In this study, we adopted an integrated workflow to assess the influence of various fracture sets on the heterogeneous carbonate reservoir rocks of the Cenomanian–Santonian Bangestan group, including Ilam and upper Sarvak Formations. For this purpose, a combination of field data was used including seismic data, core data, open-hole well-logs, petrophysical interpretations, and reservoir dynamic data. FMI interpretation revealed that a substantial amount of secondary porosity exists in the Ilam and Sarvak Formations. The upper interval of Sarvak 1-2 (3491 m to 3510 m), Sarvak 1-3 (3530 m to 3550 m), and the base of Sarvak 2-1 are the most fractured intervals in the formation. The dominant stress regime in the study area is a combination of compressional and strike-slip system featuring reverse faults with a NW–SE orientation. From the depositional setting point of view, mid-ramp and inner-ramp show a higher concentration of fractures compared to open marine environment. Fracture permeability was modeled iteratively to establish a realistic match with production log data. The results indicate that secondary permeability has a significant influence on the productivity of wells in the study area.
PubDate: 2023-04-01
- A new method of evaluating well-controlled reserves of tight gas sandstone
reservoirs
Abstract: Abstract Based on static geology and dynamic production of typical wells in Yan'an gas field, a convenient method of the wells controlled reserves was established combining with material balance method (MB). The method was applied to 88 wells in Yan'an tight gas field. The results show that: ①Controlled by pore structure, wells are divided into three types based on the morphology of the capillary pressure curve and the analysis of the parameter characteristics, and their productivity is evaluated, respectively. ②The flow material balance method (FMB) ignores the change of natural gas compressibility, viscosity and Z in the calculation. After the theoretical calculation of 30 gas samples, the slope of the curve of the relationship between bottom hole pressure and cumulative production and the slope of the curve of the relationship between average formation pressure and cumulative production are not equal. ③Compared with the results of the MB, the result of the FMB is smaller, and the maximum error is 34.66%. The consequence of the modified FMB is more accurate, and the average error is 2.45%, which has good applicability. The established method is simple, only requiring production data with high precision, providing a new method to evaluate well-controlled reserves of tight gas sandstone. This method with significant application value can also offer reference values for other evaluating methods of well-controlled reserves.
PubDate: 2023-04-01
- A comprehensive method for determining the dewaxing interval period in gas
lift wells
Abstract: Abstract The gas lift method is an artificial lift method of well production using the energy of compressed gas injected into the well to lift the reservoir fluid to the surface. The formation of paraffin deposits has remained one of the critical oil production problems due to the growing percentage of hard-to-recover reserves in the overall structure. This complication is also typical for many oil and gas fields in Vietnam, such as the White Tiger, White Bear, and Dragon fields. Wax deposit formation negatively affects the operation of individual production wells and the development of the field as a whole, which leads to a decrease in productivity and the need to take measures to remove paraffin deposits, subsequently increasing the downtime period of the well. In order to ensure stable production of highly paraffinic oil, it is necessary to take measures to dewax wells systematically. The frequency of wax removal operations depends on the intensity of the wax formation, which is determined by various technological, technical, and geological factors. The interval between dewaxing operations is called the dewaxing interval period (DIP). This value is an important technological parameter and characterizes the efficiency of a well’s operation. In this study, a comprehensive method has been developed to determine the dewaxing interval period (treatment interval) for gas-lift wells when the formation of wax deposits has occurred. The optimal dewaxing interval period is suggested to be determined by the change in the liquid well flow rate at the point when it falls by 20% from the initial value. In addition, a mathematical model of the time-dependent wax thickness, taking into account the heat and mass transfer laws and the laboratory results using the Cold Finger method, has also been developed. The proposed model for determining the dewaxing interval period was applied to an oil well in Vietnam. The DIP prediction model gave a similar value to the actual DIP field data (6.67 and 6 days, respectively). The obtained results showed that the model had proven its accuracy following the results of a comparison with the field's data of dewaxing operations.
PubDate: 2023-04-01
- Stress evolution and fracture propagation of infill well after production
and injection of parent well in a tight oil reservoir
Abstract: Abstract Stimulation of unconventional tight oil formations via horizontal wells has seen increasing cases of fracturing infill wells in recent years. The effectiveness of such a strategy is mainly dependent on the proper characterization of the stress evolution and an accurate forecast of the subsequent fracture propagation in the region neighboring the infill wells after considering the production performance and the injection schemes of the parent wells. In this respect, a comprehensive approach was proposed to simulate the stress evolution caused by the production and injection of the parent wells. The approach can also predict the upcoming fracture propagation behavior of the infill well. It was found that depletion in the parent wells can result in dramatic changes of the stress field, highlighted by apparent decreases in the magnitude of the minimum horizontal stress and changes in its orientation. Controlled injection in the parent wells can reproduce the original stress field, which favors the transverse extension of the fracture network in the infill well. In contrast, soaking well alone has little effect on improving the stress field. Therefore, this study suggests optimal injection schemes for parent wells and provides insights for fracture cluster designs in an infill well, eventually leading to maximized productivity of the infill well.
PubDate: 2023-04-01
- A simulation study of hydraulic fracturing design in carbonate reservoirs:
a middle east oilfield case study
Abstract: Abstract The interactions between hydraulic fracture morphology and fluid transport mechanisms after large-scale fracturing in low-permeability carbonate reservoirs are important factors that could impact post-fracturing productivity. Using an integrated geology-engineering approach that consists of hydraulic fracturing and reservoir simulation, this paper presents the detailed hydraulic fracturing simulation and design of a low-permeability carbonate reservoir in the Middle East based on sweet spot mapping. The fracturing protocol is determined based on productivity charts, which are obtained via sweet spot mapping of the target carbonate reservoir. The daily production of a horizontal well in the reservoir shows an increase from 870 to 2000 bbl/d after the hydraulic fracturing design and implementation, which is the highest among the existing production wells in same oilfield. The results are shown to be consistent with the proposed productivity chart, which suggests that the implemented workflow could be helpful for the large-scale fracturing implementation of similar carbonate reservoirs.
PubDate: 2023-04-01
- Review of underbalanced drilling techniques highlighting the advancement
of foamed drilling fluids
Abstract: Abstract Overbalanced drilling is the most common drilling technique; nevertheless, it has several disadvantages such as formation damage, mud losses, and stuck pipes; challenges that are common in high permeability zones and highly fractured formations. To overcome those issues, the underbalanced drilling method could be implemented. The underbalanced drilling (UBD) technique is widely utilized in hard, under pressure, depleted, and fractured/vuggy formations. Low-density drilling fluids are usually used in UBD operations and could be categorized into a gas (i.e., air, nitrogen, and natural gas) or two-phase (i.e., mist and foam). Although foamed fluid attracted attention in enhanced oil recovery and hydraulic fracturing operations, it is ideal for UBD operations due to its low density and efficient transport capacity. This paper highlights the applications, limitations, advantages, and disadvantages of UBD operations. It also discusses the drilling foam chemistry, structure, characterization, and rheological properties. Finally, this paper highlights a few successful UBD operations utilizing foamed drilling fluids worldwide.
PubDate: 2023-04-01
- Delineating the main structural outlines and the petrophysical properties
of the Albian-upper Cretaceous Reservoirs using seismic and well log data,
Shushan Basin, north Western Desert, Egypt
Abstract: Abstract This study concerns with delineating and analyzing the subsurface structural setting of Khalda Oil Field at Shushan Basin as a key factor for evaluating the petrophysical properties and the deliverability of the Bahariya Formation. Shushan Basin is considered one of the most prospective basins in the Western Desert. The oil is trapped within a gentle seismically defined anticline that contains a series of coastal sandstone reservoirs interbedded with a neritic and tidal flat mudstone and a few carbonate interbeds of the Albian-Cenomanian Bahariya Formation forming multiple oil-bearing sandstone reservoirs. A set of borehole logging and seismic data were available, tied, processed, and mapped to delineate the predominant structures in the study area. Results show the implication of the NW–SE, NE–SW, and E–W gravity faulting on the Bahariya and the overlying Abu Roash formations. This set of gravity faults is attributed to the Mesozoic tensional stresses. The depth structure contour maps on the upper surfaces of the Lower and Upper Bahariya members reveal the presence of some NE–SW gravity faults that dissected the Khalda Field into some slightly tilted blocks, shallowing in depth to the south as deepening to the north. Besides, the study area has been affected later in the Jurassic by E–W gravity faults during the Atlantic Ocean opening. This faulting trend was changed later into the NE–SW direction as a result of the movement of North Africa against Laurasia. The petrophysical analysis indicated that the Lower Bahariya sandstone reservoir has a good reservoir quality (16 ≤ ∅ ≤ 25%, 53 ≤ Sw ≤ 59%, 6.0 ≤ Vsh ≤ 32.2%, and good net-pay thickness 18.0–38.0 ft). It is revealed that the drilled wells penetrating the crest of the anticline are prospective while that located in the anticline flanks are water-bearing recommending exploration away from the anticline flanks. By applying this workflow, it is possible to explore for the similar subsurface hydrocarbons-bearing sequences in the Western Desert and North Africa in future exploitation plans.
PubDate: 2023-04-01
- Application of machine learning to determine the shear stress and
filtration loss properties of nano-based drilling fluid
Abstract: Abstract A detailed understanding of the drilling fluid rheology and filtration properties is essential to assuring reduced fluid loss during the transport process. As per literature review, silica nanoparticle is an exceptional additive to enhance drilling fluid rheology and filtration properties enhancement. However, a correlation based on nano-SiO2-water-based drilling fluid that can quantify the rheology and filtration properties of nanofluids is not available. Thus, two data-driven machine learning approaches are proposed for prediction, i.e. artificial-neural-network and least-square-support-vector-machine (LSSVM). Parameters involved for the prediction of shear stress are SiO2 concentration, temperature, and shear rate, whereas SiO2 nanoparticle concentration, temperature, and time are the inputs to simulate filtration volume. A feed-forward multilayer perceptron is constructed and optimised using the Levenberg–Marquardt learning algorithm. The parameters for the LSSVM are optimised using Couple Simulated Annealing. The performance of each model is evaluated based on several statistical parameters. The predicted results achieved R2 (coefficient of determination) value higher than 0.99 and MAE (mean absolute error) and MAPE (mean absolute percentage error) value below 7% for both the models. The developed models are further validated with experimental data that reveals an excellent agreement between predicted and experimental data.
PubDate: 2023-04-01
- Study on deposit formation model in sulfide-containing natural gas
environment
Abstract: Abstract The breathing pipe of a produced water storage tank in a sulfide-containing natural gas station is prone to deposit formation, which leads to pipeline blockage. In this study, scanning electron microscopy (SEM), energy-dispersive X-ray spectroscopy (EDS), and X-ray diffraction (XRD) analyses of the deposit in breathing pipe show that the deposit is composed of elemental sulfur and corrosion scales of ferrous polysulfide and ferrous sulfate. Existing deposit formation prediction models cannot predict the formation of elemental sulfur and corrosion scales in sulfide-containing environments. Herein, based on thermodynamic models of elemental sulfur and corrosion scale formation, deposit formation models of elemental sulfur, ferrous polysulfide, and ferrous sulfate scale formation are established. It is found that deposition of elemental sulfur and ferrous polysulfide increases with decreasing temperature of the breathing tube. Corrosion of pipe in the precipitating corrosive water leads to higher activity of \(\left[{\mathrm{Fe}}^{2+}\right]\) on the inner wall of the pipe carried by the sulfide-containing natural gas. Consequently, ferrous polysulfide and ferrous sulfate are easily deposited when the activity products of ferrous, sulfide, and sulfate ions are higher than the thermodynamic solubility product constant. The aforementioned prediction models are applied to predict the deposition of ferrous polysulfide, ferrous sulfate corrosion scale, and elemental sulfur using the chemical composition data of gas and precipitating water in the breathing pipe of the produced water tank of TB101-X1 well. The prediction results of the models are consistent with those of actual chemical composition analysis, which verifies the accuracy and reliability of the models.
PubDate: 2023-04-01
- The effect of polypropylene fiber on the curing time of class G oil well
cement and its mechanical, petrophysical, and elastic properties
Abstract: Abstract The cement paste is subjected to various loads throughout a well’s life, which may compromise some of its essential characteristics and impair its performance. When the cement paste is first being formed and the cement’s characteristics have not yet fully matured, these loadings take on greater importance. In this study, the early properties of cement used in oil wells that contains polypropylene fiber are assessed. Five different curing times were used to prepare ten cement samples (6, 12, 24, 48, and 72 h). Five samples contained polypropylene fiber, while the remaining five samples were without polypropylene fibers. After the samples were prepared, the examination of several early cement properties took place. Nuclear magnetic resonance (NMR) was used to describe each sample in order to determine how the curing times affected the cement’s porosity. The findings demonstrated that both cement systems’ compressive and tensile strengths increased with curing time, and that adding polypropylene fiber enhanced the cement’s strength. The porosity and permeability of the cement specimens were significantly reduced with the incorporation of polypropylene fibers, as well as with time during the curing process for both cement samples. The reduction of Young’s modulus and the increase in Poisson’s ratio show that the addition of polypropylene fibers also makes the cement more elastic. To express variations in porosity as well as compressive and tensile strengths, logarithmic relationships were constructed. While the Poisson’s ratio, Young’s modulus, density variations, and permeability were precisely modeled by power-law equations.
PubDate: 2023-04-01
- Petroleum source rock potential evaluation: a case study of block 11a,
Pletmos sub-basin, offshore South Africa
Abstract: Abstract Among the several existing geochemical methods in hydrocarbon exploration, the technique linking total organic carbon content (TOC) and Rock–Eval pyrolysis is most widely used, largely as a result of its capacity to rapidly provide vital information regarding the identification of source rocks and their defining characteristic, as well as thermal maturity levels and generative potentials. In this study, data from prospective source units within the southern depocenter of the Pletmos Sub-basin were analyzed using this geochemical method. Cutting samples from six wells in Block 11a were subjected to organic geochemical analysis to understand the occurring hydrocarbon scenario. Based on the results of the investigation, five notable source rock intervals of Kimmeridgian to Turonian ages were identified. The source rocks are shales with both indigenous and non-indigenous organic matter. Their TOC values show a fair to excellent petroleum generating potential, with the Aptian and Kimmeridgian intervals having the highest and lowest, respectively. The Hydrogen Index (HI), along with S2/S3 ratio values, typifies a predominance of mixed type II/III (oil/gas-prone) with some type III (gas-prone) and II (oil-prone) kerogens. The trends of the maturity parameters Tmax and Ro (vitrinite reflectance) indicate maturities ranging from immature to a late stage of maturity (dry gas window). Two observed breaks in the Ro profile reveal a possible link of maturity to high heat flow that is allied to sedimentation and tectonic uplift during the Late Cretaceous. Generally, based on TOC, S1, and HI, the petroleum potential trend increases with increasing depth, with a striking display of mixed hydrocarbon generating potential. Interpreted hydrocarbon typing is thus recommended to support the well-testing analysis.
PubDate: 2023-04-01
- Prior assessment of CO2 leak rate through cracks sealed by nanoparticle
gels
Abstract: Abstract The leakage of hydrocarbon fluids through cracks in the annular cement and CO2 storage is a major concern to the Petroleum Industry. A significant risk is posed when repairing leakage in a micro annuli channel with smaller apertures. A low-viscosity sealant that can generate a long-lasting resilient seal is desired. The solution to sealing these channels might lie in a novel application using nano-silica Gel. In this study, laboratory tests were carried out to examine the capabilities of nano-silica gels to seal the cracks. Analyzing its rheological property, the gel strengths of nano-silica gels were found to increase with an increase in nano-silica concentration. Additionally, it was discovered that as the concentration of nano-silica increases, the sealing and leakage pressures, defined as the pressures before and after water breakthrough, respectively, increase as well. With a typical 15% concentration of nano silica in gel, a sealing pressure gradient of 80.2 psi/in and a leakage pressure gradient of 30 psi/in at a leaking rate of 1 cc/min were noted. To validate the validity of the experimental results, a mathematical model was developed to predict the leakage rate of sealed fractures. The model suggests that the young’s modulus of sealant is a key property of nano-sealants and further investigations are needed to validate the mathematical model for quantitative use. This study suggests a novel strategy for enhancing cement zonal isolation and reducing cement failure in oil and gas sector.
PubDate: 2023-03-25
- Quantitative characterization of igneous rock thermal effect on sandstone
reservoir reconstruction based on heat conduction
Abstract: Abstract The X oilfield is the first sandstone reservoir under the influence of igneous rock, which is discovered and put into development in Bohai Sea. Compared with the conventional sandstone reservoir, the oilfield is affected by magmatic activity, the reservoir heterogeneity is serious and the micro pore structure is complex, which results in the poor correlation between mobility calculated by traditional methods and specific oil production index. In order to predict oil well productivity and guide oilfield well location deployment, the quantitative transformation of sandstone reservoir affected by igneous rock is studied in this paper. According to the distribution mode of igneous rock in the reservoir, a permeability model of quantitative characterization for sandstone reservoir permeability is established, in which the influences of heat conduction, reservoir skeleton deformation and stress sensitivity are considered, and then the igneous rock influence on the ground temperature field of surrounding rock is simulated by ANSYS software. According to the relationship between porosity and permeability, the quantitative transformation effect of igneous rock thermal effect on sandstone reservoir is quantitatively characterized. The reservoir temperature field variation law, different baking types and igneous rock thickness influence on the transformation degree of sandstone reservoir are analyzed. Finally, the X oilfield is taken as an example to verify the research method, and the second batch of wells location deployment is successfully guided. The results show that the thermal effect of igneous rock reduces the permeability of reservoir, and the temperature of reservoir increases first and then decreases with time, the rising speed is faster than the falling speed, with the increase in distance from igneous rock, the maximum temperature of reservoir shows a downward trend, in the case of baking on both sides, the heat of igneous rock is greater, which makes the temperature of surrounding reservoir rise more, and the transformation effect on reservoir is more obvious. The influence range of igneous rock thickness on permeability is basically the same, but with the increase in thickness, igneous rock has a greater influence on surrounding rock. The research example of the X oilfield shows that the existence of igneous rock reduces the reservoir physical properties of development wells by 1.2–5.9 times. The correlation between igneous rock physical properties and specific oil production index corrected by this method can reach 0.9478. By avoiding igneous rock, the comparative production of the second batch of development wells is 1.5 times that of the first batch of development wells.
PubDate: 2023-03-23
- Cutting mechanism of a special 3D concave-shaped PDC cutter applicable to
the Weiyuan shale
Abstract: Abstract The Weiyuan shale gas field faces problems of long drilling cycles and high development costs. Improving the drilling efficiency of polycrystalline diamond compact bits in shale formations will significantly reduce the overall well cost and duration. Previous applications have demonstrated that conventional PDC bits on the market cannot meet the demand for drilling acceleration. In this work, a new three-dimensional concave-shaped PDC cutter was proposed to improve drilling efficiency. The special 3D concave-shaped cutter has two symmetrical curved ridges on the concave surface and a circular plane at the center. The cutting mechanism of the new 3D concave-shaped cutter has been studied by laboratory experiments and numerical simulations. The research data revealed that, compared with a flat cutter, the tangential force of the original 3D concave-shaped cutter was reduced by 1.4%–35.0%, the axial force was reduced by 6.7%–37.6%, and the mechanical specific energy (MSE) was reduced by 1.6%–35.59%. Simulations showed that the shear action of the 3D concave-shaped cutter was divided into two continuous parts, with the sides and the center surface being stressed successively, which is helpful for extending shear cracks, forming trilobal cuttings, and improving cutting efficiency. With the special 3D concave-shaped cutter, an 8½-inch drill bit was designed and manufactured and tested on the Longmaxi shale in the Weiyuan block. Through field tests, we further compared the performance of the 3D concave-shaped cutter PDC bit with that of the flat cutter PDC bit. The 3D concave-shaped PDC bit had a 41.8% better footage and 22.6% better rate of penetration (ROP) in field test.
PubDate: 2023-03-22
- Study on influence of failure mode on fracturing performance of fractured
reservoir
Abstract: Abstract Reasonable volumetric fracturing effect evaluation is the key to effective stimulation of fractured reservoir. Traditional fracturing effect evaluation is mainly conducted by the SRV (stimulated reservoir volume), fracture length, fracture width and other indicators, ignoring the influence of failure mode on fracturing performance. In this paper, the different fracture modes including main fractures, branch fractures and self-supporting fractures contained in the fracture network and their contributions to fracturing effect were studied in depth by numerical simulation. The results show that the main fracture formed by tensile failure has the largest width but simple shape and relatively small distribution range, while the branch fracture has a slightly smaller width but effectively expands the main fracture. Although the self-supporting fracture by shear failure is not connected, it can still improve the overall flow conductivity. The angle and number of natural fractures in fractured reservoir have a significant effect on fracture network scale and fracturing effect. When the number of natural fractures is larger, both of the number and proportion of branching fractures and self-supported fractures are larger, although the isolated self-supported fractures account for a larger proportion, the overall flow conductivity of the final fracture network is stronger. When the angle of natural fractures is larger, the natural fractures in uniform stress field are easier to be connected by hydraulic fractures and the final fracturing effect is better. The research methods and results have a certain guiding significance for the evaluation of volumetric fracturing effect in fractured reservoirs and are conducive to the reasonable selection of favorable fracturing areas and engineering parameters.
PubDate: 2023-03-17
- Application of machine learning algorithms in classification the flow
units of the Kazhdumi reservoir in one of the oil fields in southwest of
Iran
Abstract: Abstract By determining the hydraulic flow units (HFUs) in the reservoir rock and examining the distribution of porosity and permeability variables, it is possible to identify areas with suitable reservoir quality. In conventional methods, HFUs are determined using core data. This is while considering the non-continuity of the core data along the well, there is a great uncertainty in generalizing their results to the entire depth of the reservoir. Therefore, using related wireline logs as continuous data and using artificial intelligence methods can be an acceptable alternative. In this study, first, the number of HFUs was determined using conventional methods including Winland R35, flow zone index, discrete rock type and k-means. After that, by using petrophysical logs and using machine learning algorithms including support vector machine (SVM), artificial neural network (ANN), LogitBoost (LB), random forest (RF), and logistic regression (LR), HFUs have been determined. The innovation of this article is the use of different intelligent methods in determining the HFUs and comparing these methods with each other in such a way that instead of using only two parameters of porosity and permeability, different data obtained from wireline logging are used. This increases the accuracy and speed of reaching the solution and is the main application of the methodology introduced in this study. Mentioned algorithms are compared with accuracy, and the results show that SVM, ANN, RF, LB, and LR with 90.46%, 88.12%, 91.87%, 94.84%, and 91.56% accuracy classified the HFUs respectively.
PubDate: 2023-03-17
