Vertical Wells Research Articles

Analysis Reveals Depth of Vaca Muerta’s Potential

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205573, “Vaca Muerta: An Emerging Shale Petroleum Reservoir,” by Rahimah B. A. Karim and Roberto Aguilera, SPE, University of Calgary. The paper has not been peer reviewed. _ The objective of the complete paper is to present geological and reservoir characterization, drilling and production strategies, historical performance, and economics of the Vaca Muerta reservoir. The word “petroleum” as used in this paper includes oil, natural gas, and natural-gas liquids. The authors conclude that oil and gas potential in the Vaca Muerta shale is significant and rivals the potential of shales widely developed in the United States and Canada. Reservoir Background In 2008, exploration activities began in the Loma Campana (LC) field, leading to Vaca Muerta’s discovery in 2010. The LC area was selected as the first factory-mode development because of its pre-existing infrastructure and accessibility. The urgency of boosting hydrocarbon production in Argentina has driven multiple companies to invest substantially in unconventional resources. The complete paper details the shale’s geological setting and reservoir characterization. Reservoir heterogeneity and its effect on productivity are described for selected development areas, including La Amarga Chica (LAC), the central area, and LC. Vaca Muerta is an attractive target for shale development because of a few factors. One is its thermal maturity that increases from east to west. This has resulted in multiple types of hydrocarbon windows, from oil to dry-gas windows. Furthermore, it is laterally extensive and has formation thickness of up to 500 m. Total organic carbon (TOC) also is high (2–10%), with a mineralogy content of less than 30% clay. At the basin level, the average matrix porosity of Vaca Muerta ranges from 4 to 14%, with a narrower range at the field or block scale. The formation shows similarities with other well-known shale plays with similar porosity volumes and pore types, such as the Haynesville (between 8 and 16%) but higher than the Eagle Ford (between 8 and 10%). Significant formation thickness drove the application of vertical wells during the first factory drilling in Vaca Muerta. It allowed placement of four to six hydraulic fractures controlled by the lithologies and vertical heterogeneity. In 2015, however, a major change from vertical to horizontal well development occurred as a result of better understanding of the formation complexity and optimal landing zones. In the past few years, operators have increased lateral length from 1000 to 2500 m to improve productivity. Most operations use multiwell pad drilling. The pad is a four-well line with 10-m spacing on the surface and a minimum of 300-m spacing in the reservoir. This well spacing is wide by US standards but is optimal for Vaca Muerta to minimize well interference in the reservoir.

Gas recovery from silty hydrate reservoirs by using vertical and horizontal well patterns in the South China Sea: Effect of well spacing and its optimization

Gas recovery from silty hydrate reservoirs by using vertical and horizontal well patterns in the South China Sea: Effect of well spacing and its optimization

Waste to Energy: Review on the Development of Land Fill Gas for Power Generation in Sub-Saharan Africa

This study focused on the development of land fill gas for power generation in Sub-Saharan Africa. In rapidly expanding cities in developing and emerging nations, it has been observed that municipal solid waste (MSW) has increased dramatically, raising public concern about the effects on the environment and public health. In Sub-Saharan Africa today, the garbage of people within this region especially in Nigeria is carelessly disposed. Environmental pollution and its effects on people's quality of life have become more sensitive topics among residents and decision-makers in Sub-Saharan Africa. Additionally, municipal solid waste management (MSWM) is becoming a more important topic on the local political agenda. Local decision-makers routinely debate whether to invest in waste-to-energy technologies as part of their effort to modernize waste management systems. Waste-to-Energy technologies are being promoted more and more as an alluring solution to a number of problems, including the urgent issue of waste disposal. These issues include inadequate power production, a shortage of landfill space, and greenhouse gas emissions from improper waste management. As an alternative to waste burning and composting, landfilling is one of the municipal solid waste (MSW) disposal techniques that are most frequently used. Due to its financial benefits, the sanitary landfill method is still often employed in various nations for the final disposal of solid waste. Landfill gas (LFG) is mostly produced by the anaerobic breakdown of the biodegradable component of municipal solid waste (MSW), specifically kitchen and yard trash, which is disposed of in landfills. Due to the anaerobic breakdown of the organic portion of solid waste, landfill gas is continuously produced. As a result, if an extraction system is not constructed in a landfill, there will be an overpressure that will force the biogas to be released into the atmosphere, which will have an adverse effect on the environment. Methane and carbon dioxide make up the majority of the gases that make up landfill gas, which is a mixture of other gases. Many landfill sites include an operational gas collection system that draws gas from both horizontal and vertical gas wells using a blower. The gas from the landfill was thought to only include carbon dioxide and methane. Methane's typical volume composition is 49%, hence it was believed that carbon dioxide would have a volume composition of 51%. Reviewing the information gathered by numerous studies regarding the volume of waste being dumped in landfills reveals that the waste produced in sub-Saharan Africa is sufficient to power the area with electricity. It was discovered that the quantity of electricity generated will fluctuate over time based on the flow rate of landfill gas. It will initially rise until a peak is attained. A million tons of landfill waste typically emits 434,000 cubic feet of LFG each day, which is sufficient to generate 0.80 MW of power. About 70% of LFG projects use internal combustion engines, gas turbines, and micro-turbines to produce power.

The role of free‐strain assumption in axisymmetric electro‐osmosis‐enhanced preloading consolidation of unsaturated soil

AbstractThe axisymmetric, equal‐strain consolidation theory of soil is widely employed in engineering due to the user‐friendliness of its solution. However, the radially averaged excess pore pressure (EPP) is unable to reveal the coupling effect of the radial electric field when the soil is consolidated by electro‐osmotic and surcharge preloading. In this paper, the axisymmetric consolidation analytical models with free strain and equal strain assumptions are developed to investigate the importance of the free strain assumption in the consolidation of unsaturated soil by electro‐osmosis‐aided preloading. The finite Hankel transform, decoupling technique, and Laplace transform are then utilised to derive the semi‐analytical solutions. Finally, the comparison of EPP, surface settlement, and average degree of consolidation under the two assumptions reveals that the free‐strain solution accurately shows the distribution of EPP at any point in the soils and the development of surface settlement at different radii, thus helping to analyse the electro‐osmotic consolidation characteristics. Moreover, it was discovered that electro‐osmosis combined with preloading allows for a more uniform consolidation of unsaturated soil. The difference in the average degree of consolidation under both assumptions is insignificant, while the installation distance of the cathode and anode vertical wells has a significant effect.

Full implicit simulator of hydrate (FISH) and analysis on hydrate dissociation in porous media in the cubic hydrate simulator

Natural gas hydrate is a promising strategic energy resource in marine and permafrost sediments. To precisely characterize the coupled Thermal-Hydraulic-Chemical (THC) process in hydrate reservoirs, a bona fide mathematical model with improved key parameters is needed. We developed a Full Implicit Simulator of Hydrate (FISH), a three-phase, four-component mathematical model, to simulate gas recovery from hydrate reservoirs. The experiment of methane hydrate formation and dissociation under depressurization via a single vertical well was executed in the Cubic Hydrate Simulator (CHS). FISH was employed to reproduce the experiment of hydrate dissociation in quartz sands. This study successfully obtains unified parameters that are suitable for the entire hydrate dissociation process. Simulation results of gas and aqueous production profiles and the temperature distribution agreed well with that in the experiment. The Mean Absolute Percentage Error (MAPE) of the simulated volume of gas produced was 2.845%. The mass conservation in the pressure vessel was confirmed by both experimental data and numerical simulation results. This numerical simulator can be applied to predict the behavior of hydrate-bearing-sediments in the laboratory or to evaluate the gas production potential from the marine or permafrost hydrate reservoirs.

Permeability anisotropy impact on wormhole propagation in openhole and limited-entry completions: A 3D numerical study

The permeability in carbonate reservoirs is not the same in all directions (i.e., anisotropic), a property seldom considered in acid stimulation. The study hypothesizes that permeability anisotropy impacts acid treatment efficiency significantly. The investigation included the openhole and limited-entry completions in a vertical and horizontal wellbores configuration. A model based on the two-scale continuum approach was constructed in three-dimensional space (3D), resembling the big block experiment with the wellbore at the center. Permeability anisotropy significantly impacts acid efficiency in terms of the pore volume to breakthrough (PVBT) and optimum injection rate. For instance, simulations of acid placement in an openhole horizontal well with 10 anisotropy ratio resulted in PVBT of 0.15 compared to 0.35 in a vertical well. Limited entry completions result in more extended wormholes where the permeability anisotropy positively impacted wormhole length as compared to isotropic permeability. Nevertheless, the permeability anisotropy negatively impacted wormhole coverage along the wellbore in most scenarios. The simulations showed that a spear-like wormhole propagates from a limited entry horizontal wellbore in anisotropic formation, which previous studies assumed to be spherical or ellipsoidal. This implies that the skin factors models should be revised based on the new findings. This is the first study to assess the permeability antitropy impact on the stimulation of openhole and perforated wells in a 3D space.

Production Capacity Variations of Horizontal Wells in Tight Reservoirs Controlled by the Structural Characteristics of Composite Sand Bodies: Fuyu Formation in the Qian’an Area of the Songliao Basin as an Example

In order to improve the combined exploitation efficiency of horizontal and vertical wells, and given the fact that the complex and varied spatial structure of sand bodies in the Fuyu oil layer in the Qian’an area of Songliao Basin leads to significant differences in production characteristics of horizontal wells, the sand body types and internal spatial structure are finely dissected according to the theory of configuration analysis, and the internal spatial structure is divided into three configuration styles: spatial clipping type, overlapping type, and separation type. Then, by comparing the productivity characteristics of horizontal wells with different configurations of sand bodies, combined with the analysis of fluid flow law under horizontal well volume fracturing, a main fracture–fracture network–matrix coupled fluid flow model in a tight reservoir based on composite sand body configuration is established. Combined with the actual volume fracturing the horizontal well area, the productivity curves of each cluster in the horizontal section after numerical simulation of volume fracturing of typical horizontal well groups are extracted, which are divided into four types: high-yield stable type, high-yield two-stage type, high-yield rapid-decline type, and low-yield rapid-decline type, and the coupling relationship between the productivity characteristics of each cluster in the horizontal well volume fracturing and sand body configuration style is established, which provides a theoretical basis for the adjustment of different sand body development methods in subsequent oilfields.

Prediction of Sanding Likelihood Intervals Using Different Approaches

Sand production is undesirable matters, occurring in wells that are producing from sand reservoirs. It causes many problems such as erosion and grains accumulation in downhole and surface equipment’s, and formation subsidence. Important stage in sanding problem solution is a prediction of likelihood sand production intervals. In present paper, a vertical well X1 that is producing from Asmari reservoir in Y field at southern Iraq was selected for study. Asmari reservoir was classified to six units: A, B1, B2, B3, B4, and C. B zones consisted from sandstone with others rock types. Eight approaches were used for prediction sanding onset intervals by dealing with X1 well as open hole completion. Utilized eight prediction methods are compressional sonic wave (CSW), unconfined compressive strength (UCS), total porosity (PHIT), shear modulus to bulk compressibility (G/Cb), B-Index, Schlumberger index (S- Index), combined index (Ec-Index) and critical drawdown pressure (CDDP). All these methods performed based on 2462 measured points of CSW, sonic shear wave log (SSW), and density log (DL). Sand production likelihood intervals was selected by determination of cutoff values of adopted methods. Sand is possible to occur if interval has values lower than cutoff values of G/Cb, UCS, B-Index, S-Index, Ec, and CDDP and greater than cutoff values of CSW, and PHIT. Obtained cutoff values of eight approaches were 800 x 109 psi2, 36 Mpa, 0.2, 80 us/ft, 10000 Mpa, 108 Mpa, and 2700 Mpa, of G/Cb, UCS, PHIT, CSW, B-Index, S-Index, and Ec respectively. As well as sand production is possible to occur of bottomhole flowing pressure lower than calculated CDDP. Some Intervals had high CDDP that referred to abnormal pressure zones consisted from shale. Determination of sand onset intervals is a key for selecting best methods for controlling.

Numerical Simulation of Optimized Step-Wise Depressurization for Enhanced Natural Gas Hydrate Production in the Nankai Trough of Japan

The utilization of natural gas hydrates as an alternative energy source has garnered significant attention due to their proven potential. Despite the successful offshore natural gas hydrate production tests, commercial exploitation has not been achieved. This study aims to enhance the understanding of gas production behavior through simulations from a single vertical well in the Nankai Trough and assess the effectiveness of the step-wise depressurization method for gas production using TOUGH + HYDRATE. The simulation results showed that the effective permeability for the water phase decreased as the hydrates were decomposed, and the invasion of the pore water from the underburden eliminated this effect. Compared with the direct depressurization method, the step-wise depressurization method significantly increased the cumulative gas production by more than 10% and mitigated the rapid generation of gas and water production during the moment of depressurization. The results also indicated that the depressurization gradient was more sensitive to the cumulative gas production than the maintenance time of depressurization. In view of the gas and water production characteristics coupled with the challenges in carrying out the step-wise depressurization method, it is suggested that a depressurization gradient of 1 MPa and a maintenance time of 1 day should be employed.

Evaluation of Reconstruction Potential for Low-Production Vertical Wells of CBM in the Southern Qinshui Basin

Production practice has shown that not all low-production coalbed methane (CBM) wells can be reconstructed into high-production wells through secondary stimulation, so it is necessary and timely to establish an evaluation index system, form an evaluation method, and evaluate the reconstruction potential of low-production wells. Based on the development practice of CBM in the southern Qinshui Basin, this paper analyzes the influencing factors of low production in vertical wells from the aspects of coal and rock reservoir conditions, drilling and completion engineering, and drainage engineering. It is proposed that the evaluation of the reconstruction potential of low-production wells should focus on the quality of CBM resources, the difficulty of CBM desorption and diffusion, and the degree of damage to coal reservoirs caused by the initial reservoir stimulation. Twelve parameters, including gas content, gas saturation, reservoir pressure gradient, critical desorption–reservoir pressure ratio, and permeability, were systematically selected as evaluation indicators, and the grading reference values for each evaluation indicator were comparatively given. Then, a multi-factor comprehensive evaluation method for the reconstruction potential of low-production wells based on gray correlation analysis method was established. The reconstruction potential of low-production wells was divided into three levels: high, medium, and low. When reconstructing low-production wells, it is recommended to prioritize the low-production wells with high reconstruction potential, followed by those with medium reconstruction potential, while low-production wells with low reconstruction potential are not recommended for reconstruction. Finally, the evaluation method was used to evaluate the reconstruction potential of five low-production wells in a CBM block, and suggestions for the reconstruction order and reconstruction potential levels for each well were given.

Numerical modeling of a geothermal reservoir with high permeability in Turkey

Geothermal resources have gained great attention because they promise to deliver geographically disperse, carbon-free energy with minimal environmental impact. Natural fracture networks have a major impact on geothermal reservoir heat extraction. The objective of our model is to evaluate the impact of natural fracture networks on a real field geothermal reservoir with high permeability in Turkey. In this work, the thermal embedded discrete fracture model (thermal EDFM) is applied to handle the thermal modeling of complex fracture networks. The thermal non-neighbor connections enable us to efficiently simulate temperature behavior within a massive complex fracture network. A semi-analytical thermal wellbore model is applied to evaluate the heat-loss inside the producer. Using the enthalpy of the producing fluid, the electricity output is evaluated. The system power outputs under different densities of natural fracture networks are compared. Our analysis shows that in geothermal reservoir with high permeability, even with high density of natural fracture networks, the improvement on system performance and efficiency is still minor. The well placement is important to circulation efficiency. In Kizildere field, the horizontal well placement plan has better system performance compared to the vertical well placement.

Application of SAGD technology in the development of super heavy oil reservoir buried medium deep

Continental super heavy oil reservoirs in China are characterized by deep burial depth, strong reservoir heterogeneity and high oil viscosity. The steam huff and puff technology are used to develop this type of reservoir, but in this development method, its oil recovery rate, oil steam ratio, and ultimate recovery are low. The benefit of the reservoir development is losses in this high cost per ton of oil. Many vertical wells injecting steam and one horizontal well-producing liquids pattern of SAGD technology (abbreviated as VERTIHORIONATAL pattern SAGD) were Innovated to solve the problems based on SAGD technology introduced from Canada. The SAGD technology introduced in Canada was made of double horizontal wells. The above horizontal well injects steam and the other horizontal well produces liquids continued (abbreviated as DOUBLE HORIZONTAL pattern SAGD). The VERTIHORIONATAL SAGD technology makes full use of the original well pattern of huff and puff and takes advantage of the thermal connectivity and underground temperature field formed by early development; At the same time, the VERTIHORIONATAL pattern SAGD technology can effectively solve the problem of steam cavity uneven expansion caused by reservoir heterogeneity by adjusting the location of steam injection vertical wells. It can also balance the liquid production in good horizontal sections and improve steam cavity formation speed by adjusting steam injection well sections and steam injection parameters. The technology has been successfully applied in the medium-deep super heavy oil reservoir in the Shu-1 area, Du84 block, Liaohe Oilfield. Seven oil wells with a daily output of 100 tons have been cultivated, and a stable production of million tons for four consecutive years. It has been built as China’s largest SAGD development demonstration area for medium-deep super-heavy oil.

Application of drilling microchips for measurement of circulating pressure and temperature in vertical wells

This study presents successful applications of drilling microchips to acquire distributed pressure and temperature data while drilling. It also presents the application of our developed method to track the drilling microchips in pipe and annulus. The measured data in the time domain are converted into a depth profile considering the slippage of drilling microchips. The method calibrates the predicted transit time with the actual transit time by varying a velocity profile parameter for both pipe and annulus sections. Over 100 drilling microchips were deployed in two batches in a vertical well. A total of 24 drilling microchips were retrieved at the surface, which showed a physical recovery rate of 25%. The field results indicate that none of the microchips were trapped for any time as sufficient pump rates were maintained throughout the job. A consistent pressure measurement in annular space is obtained from the results of drilling microchips. A unique circulating temperature profile for all the deployed microchips is obtained. It is realized that a short break in circulation may not significantly affect the circulating fluid temperature, but significant pressure changes can be detected from the pressure results. The measured pressure data provide new insights about the tracking of drilling microchips in flow conduits and allow obtaining distinct velocity profile parameters in both pipe and annulus. The method is useful for acquiring downhole data in critical zones where the application of logging tools is risky.

Study Investigates Ineffectiveness of Acid Fracturing for Tight Reservoir Rock

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209264, “Ineffectiveness of Acid Fracturing for Stimulating a Tight Fractured Reservoir Rock: A Case Study,” by Huda R. Al-Enezi, Kuwait Oil Company, and Iraj Ershaghi, SPE, University of Southern California. The paper has not been peer reviewed. _ The complete paper describes the analysis of actual performance data for acid fracturing in a tight carbonate formation and the ineffectiveness of the process as measured by the performance responses of the producing wells. An included case study relates to a tight formation that is considered a reservoir rather than a source rock. The formation permeability is in the range of 0.1–5 md. Development has been through numerous horizontal wells with limited multistage acid stimulation. Analysis of performance data for more than 30 wells indicates no fracture flow and very limited stimulated production. Background A category of tight conventional reservoir rocks exists that has not been subjected to horizontal drilling and multistage fracturing. The objective of the authors’ study is to analyze the ineffectiveness of treatment response under acid fracturing and explore the potential of implementing multistage fracturing for a tight reservoir rock using experience gained from unconventional resources. The subject reservoir is a tight carbonate of the Middle Cretaceous age with porosity ranges between 15 and 19% and an average thickness of approximately 90 ft. Oil viscosity ranges between 2.06 and 2.54 cp and average oil gravity is 25° API. The reservoir is a depletion-drive type where the main natural energy is provided by gas in solution. Among the initial wells, only six were successful. The field is very complex, based on stratigraphic and structural characteristics. The first horizontal well was drilled during 2015–16 and was subjected to seven-stage acid fracturing. This resulted in a substantial increase of well cumulative production compared with that of vertical wells. The development plan of this field was implemented with horizontal wells with laterals extending approximately 3,000 ft. Each well was subjected to multistage acid fracturing. Examination of performance data indicated that producing wells suffered from rapid pressure depletion after a production period of 3–6 months. Wells cease natural flow and cannot sustain production even after what is considered acid fracturing without the help of artificial lift. Conventional production plots show that typical performance begins with a high initial rate for a short duration followed by a sharp decline before a stabilization period. To improve and recommend a proper hydraulic fracture design, the authors studied the effectiveness of current stimulation to develop alternative improvement procedures. Methodology The effectiveness of acid stimulation was analyzed and evaluated by using historical production for 4 years. To study the initial rates seen on these horizontal wells, a productivity-prediction tool was used to inversely compute the effective formation-permeability responsible or the observed initial production on these wells. Production data were used to inversely calculate the geometrical averaged permeability from initial field-production data assuming that the initial conditions followed a steady-state regime.

Technique Evaluates Polymer Injectivity in High-Salinity/High-Temperature Carbonates

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 211451, “Assessment of World-First Two-Polymer Injectivity Tests Performed in Two Giant High-Salinity/High-Temperature Carbonate Reservoirs Using Single-Well Simulation Models and Pressure-Falloff Analysis,” by Juan M. Leon, Shehadeh K. Masalmeh, SPE, and Ali M. Al-Sumaiti, SPE, ADNOC, et al. The paper has not been peer reviewed. _ The complete paper presents the interpretation of two polymer injectivity tests (PITs) performed in two giant light-oil high-salinity/high-temperature (HS/HT) carbonate reservoirs onshore Abu Dhabi. The detailed data acquired in both tests were used to evaluate both polymer injectivity at representative field conditions and in-depth mobility reduction. The interpretation of the pressure transient analysis (PTA) of the pressure falloffs (PFOs) and the mechanistic 3D simulation models of the two PITs confirmed the generation of polymer banks and demonstrated effective propagation of the polymer into the reservoirs at target concentrations and representative rates of future interwell pilots. Introduction The reservoirs tested in the PITs can be described as heterogeneous carbonate reservoirs divided into upper and lower zones. Upper-zone porosities range between 20 and 30%; permeability ranges from 10 to 1000 md. In contrast, the lower zone has porosities and permeabilities ranging from 10 to 30% and from 1 to 20 md, respectively. The main production mechanisms in the reservoirs are peripheral water injection, middip-pattern water injection, and crestal hydrocarbon gas injection in the gas cap. The reservoirs have been developed through long horizontal wells oriented into the lower zones to allow a more-homogeneous sweep. However, the injected fluids in the lower zone travel quickly through the upper zone not far from the injection wells and around the producers into the lower zone. This water or gas inverse coning results in bypassed oil in the lower zone. To face this challenge, the operator has investigated simultaneous injection of miscible CO2 gas and polymer (SIMGAP) for reservoirs with an approximately 10-fold permeability contrast between the lower and upper zones and simultaneous injection of water and polymer (SIWAP) for reservoirs with a permeability contrast of 100-fold or greater between the lower and upper zones. These techniques rely on reducing mobility by polymer injection in the upper zone to provide a pressure barrier and reduce crossflow of the higher-mobility fluid injected into the lower zone. PIT Simulation Model Setup A single-well radial simulation model was built for PIT 1 to assess near-wellbore phenomena by minimizing in-situ velocity and shear-rate calculation errors compared with Cartesian coordinate grids. For interpretation of PIT 2, a mechanistic Cartesian 3D thermal black-oil simulation model was built by extracting a subsector from the last available static geomodel, preserving well architecture and grid resolution in the extracted subsector. The radial simulation model was found unsuitable for PIT 2 because the injector well presented a very high deviated section in the target reservoir, while the long string presented a long horizontal section. Therefore, the polymer injectivity and polymer bank propagation in the upper reservoir might not be represented properly using a vertical well. Different local-grid-refinement (LGR) levels were implemented around the perforation length (upper zone), while the lower zone was in the root grid. The minimum cell radius in the model was determined to be 1.3 ft to avoid errors in well-index calculations considering the well-flow model. Thus, three LGR levels were applied.

Fluid Flow Regimes Analysis on Drilling Fluid Circulation for Cuttings Lifting in Vertical Drilling Oil Wells

Fluid Flow during the circulation of the drilling fluid is an important parameter that affects the process of successful lifting of cuttings during drilling activities. Researcher analyzed the regimes of the drilling fluid flow in vertical drilling wells through the analysis of the velocity calculation of the drilling fluid in the pipeline at conditions in the Drillpipe (v DP) of 21.11791 fps and in drill collar of (v DC) is 42.98293 fps, the velocity of drilling fluid in the annulus between the Casing and the Drill pipe is 1.14993 fps, 1.373781 fps between Open Hole and Drill pipe, and 1.594947 fps between Open Hole and Drill Collar, the critical velocity of drilling fluid in the pipeline and in the annulus, Reynolds number in the pipeline is 15986.36, inside Drill Collar of 22807.21, and in the annular between the Casing and the Drill pipe is 2847.435, between Open Hole and Drill pipe 3037.264, and 2679.938 between Open Hole and Drill Collar, and the velocity at which the drill cutting drops when in the annulus in all three zones is 0.14914 fps. The results of the analysis of fluid flow that occurs are found that in the pipe there is a turbulent flow and in the annulus a laminar flow occurs. In addition, the results of the analysis of the comparison between the velocity of the drilling fluid in the annulus and greater than the velocity of descent of the cuttings show that the cuttings can be lifted by the drilling fluid successfully. This indicates that the fluid lifting process is successful.

Study of Multibranch Wells for Productivity Increase in Hydrate Reservoirs Based on a 3D Heterogeneous Geological Model: A Case in the Shenhu Area, South China Sea

Summary So far, a total of 11 hydrate trial production projects have been carried out all over the world, all of which used a single vertical well or horizontal well to carry out hydrate production by the depressurization method or depressurization combined with other methods. These traditional production methods have some limitations: The single vertical well has a small contact area with the reservoir, and the transmission range of the temperature and pressure is limited; therefore, the productivity is low. The horizontal well can improve hydrate productivity from magnitude order; however, there is a long distance from the standard of commercial production of marine hydrate. Therefore, it is an inevitable trend to find a highly efficient and advanced drilling technology for heterogeneous hydrate reservoirs. The multibranch wells based on horizontal wells can not only increase the contact area between the hydrate reservoir and well by branch structure to improve the conductivity of the reservoir temperature and pressure but also improve the hydrate productivity by laying the branch at high hydrate saturation for areas with extremely uneven distribution. Therefore, for this paper, we chose the Shenhu area as the research area to establish an approximate realistic 3D heterogeneous geological model contained with hydrate, then we laid the multibranch wells based on horizontal wells in high hydrate saturation area and optimized the branch direction, location, and spacing, and the production increasing effect was assessed. Finally, an optimal multibranch well scheme was obtained under the conditions of this paper setting, which is as follows: The vertical multibranch well was set at the root end of the horizontal main well with a branch spacing of 10 m, and the productivity after optimization was 31.64% higher than that before optimization.

COMPARATIVE ANALYSIS OF THE ANALYTICAL AND NUMERICAL METHODS FOR CALCULATING THE STRESS-STRAIN STATE OF THE NEAR-WELLBORE ZONE BASED ON THE ELASTIC MODEL TAKING INTO ACCOUNT THE MAIN STRUCTURAL ELEMENTS OF THE WELL

Link for citation: Popov S.N., Chernyshov S.E., Krivoshchekov S.N. Comparative analysis of the analytical and numerical methods for calculating the stress-strain state of the near-wellbore zone based on the elastic model taking into account the main structural elements of the well. Bulletin of the Tomsk Polytechnic University. Geo Аssets Engineering, 2023, vol. 334, no. 5, рр.94-102. In Rus. The relevance of the research is caused by the scientific interest in calculating the near-wellbore zone stress-strain state to improve the development of oil and gas fields, to predict the casing stability and the safety of the cement stone. The main aim: based on a comparative analysis of the methods of analytical and numerical simulation of stress calculation near a vertical well using an elastic model, determine the distribution of radial and tangential stresses, compare the accuracy of their calculation by different methods and identify the advantages and disadvantages of each of them. Objects: near-wellbore zone of the terrigenous reservoir of the Achimov deposits of one of the fields of the Khanty-Mansiysk autonomous region. Methods: analytical and numerical finite element methods for stress-strain state calculating of the near-wellbore zone, taking into account the main structural elements of the well and using a linear elastic model. Results. The paper considers the analytical relationships used to calculate the radial and tangential stresses in the casing, cement stone and reservoir rock, as well as the equations used in numerical finite element modeling of stresses near a vertical well. The authors have developed a finite element scheme of the near-wellbore zone, including its main structural elements. The paper introduces the results of calculation of the main components of the stress tensor in the structural elements of the well depending on the radial coordinate for the bottom hole pressure of 20, 40 and 60 MPa. The authors carried out the comparative analysis of the stress calculations results by the methods used. It is shown that the largest discrepancy between the analytical and numerical methods was 2 % that corresponds to radial stresses for the calculation option with a bottom hole pressure of 20 MPa. On average, the discrepancies were: for radial stresses – 0,04 %, for tangential stresses – 0,72 %. It is concluded that when using the model of a linearly elastic medium and under boundary conditions in the form of fixing the model in the upper and lower parts along the normal to the surface, and also without taking into account the pressure distribution in the depression funnel of the model, it is sufficient to use the analytical method of calculation. If it is supposed to use combined boundary conditions, a poroelastic model, taking into account viscoplastic deformations, then it is most preferable to use the numerical simulation method.

FEATURES OF DETERMINING FILTRATION PARAMETERS OF COMPLEX CARBONATE RESERVOIRS AT THEIR OPERATION BY HORIZONTAL WELLS

Link for citation: Salnikova O.L., Chernykh I.A., Martyushev D.A., Ponomareva I.N. Features of determining filtration parameters of complex carbonate reservoirs at their operation by horizontal wells. Bulletin of the Tomsk Polytechnic University. Geo Аssets Engineering, 2023, vol. 334, no. 5, рр.137-147 In Rus. The relevance of the research is caused by the fact that in the conditions of continuous deterioration in the structure of hydrocarbon reserves, complex technologies for their development are being implemented, based, among other things, on the use of wells of complex design (horizontal wells). The increase in the share of horizontal wells in the total operating stock determines the relevance of the scientific and methodological justification of research technologies that comprehensively take into account the structural features of the reservoir and the geometry of the fluid flow. The most complete volume of geological and field information can be obtained by combining two main types of research – geophysical and hydrodynamic. The problem of data, in fact, of the indirect research methods, should be considered the need to assess the reliability of their results and the lack of approaches to reduce interpretation uncertainties, which is especially important in the conditions of the impossibility of coring in horizontal wells. This article proposes possible directions for solving these problems. The main aim of the study is the scientific substantiation of approaches to research and interpretation of their results, allowing reliably determining the filtration parameters of productive formations during their operation with horizontal wells. Object: complex Tournaisian-Famenian carbonate reservoirs in Perm region, operated by horizontal wells. Methods: geophysical and hydrodynamic studies of wells, laboratory core studies, multivariate statistical modeling. Results. It has been established that geophysical studies (interpretation was made in accordance with the algorithms for vertical wells) do not allow reliably estimating the length of the horizontal section of the wellbore and the filtration properties of the reservoir. It is recommended to determine the filtration properties when interpreting the data of hydrodynamic studies of wells. Algorithms of modern methods of interpretation of hydrodynamic studies, implemented in common software products, allow you to determine a large amount of geological and field data, including a number of parameters specific to horizontal wells. However, this procedure is accompanied by uncertainties, for example, in terms of the choice of interpretation models. The performed multivariate statistical modeling made it possible to substantiate the methodology for reliably determining the filtration properties of the reservoirs under consideration and the approach to reduce uncertainties when choosing interpretation models.

Genesis of Low CBM Production in Mid-Deep Reservoirs and Methods to Increase Regional Production: A Case Study in the Zhengzhuang Minefield, Qinshui Basin, China.

With the increase of the burial depth of the no. 3 coal seam in the Zhengzhuang minefield of Qinshui Basin, the production of surface coal bed methane (CBM) vertical wells was low. By means of theoretical analysis and numerical calculation, the causes of low production of CBM vertical wells were studied from the aspects of reservoir physical properties, development technology, stress conditions, and desorption characteristics. It was found that the high in situ stress conditions and stress state changes were the main controlling factors of the low production in the field. On this basis, the mechanism of increasing production and reservoir stimulation was explored. An L-type horizontal well was constructed alternately among the existing vertical wells on the surface to initiate a method to increase the regional production of fish-bone-shaped well groups. This method has the advantages of a large fracture extension range and a wide pressure relief area. It could also effectively connect the pre-existing fracture extension area of surface vertical wells, realizing the overall stimulation of the low-yield area and increasing the regional production. Through the optimization of the favorable stimulation area in the minefield, 8 L-type horizontal wells that adopted this method were constructed in the area with high gas content (greater than 18 m3/t), a thick coal seam (thicker than 5 m), and relatively rich groundwater in the north of the minefield. The average production of a single L-type horizontal well reached 6000 m3/d, which was about 30 times that of the surrounding vertical wells. The length of the horizontal section and the original gas content of the coal seam had a significant influence on the production of the L-type horizontal wells. This method for increasing the regional production of fish-bone-shaped well groups was an effective and feasible low-yield well stimulation technology, which provided a reference for increasing the production and efficiently developing CBM under the high-stress conditions in mid-deep high-rank coal seams.