Horizontal Drilling Research Articles

Prediction of formation pressure based on numerical simulation of in-situ stress field: a case study of the Longmaxi formation shale in the Nanchuan area, eastern Chongqing, China

The in-situ stress and formation pressure are important parameters in shale gas development. They directly affect the well wall stability, the direction of horizontal well drilling, and the fracturing effect during the shale gas development process. There are abundant shale gas resources in the southeastern Chongqing-Sichuan area, but the structure in the area is complex, and it is difficult to predict the in-situ stress and formation pressure. Therefore, in this paper, a finite element simulation model was established based on a large number of seismic, logging, and experimental rock mechanics data and the prediction accuracy of the stress field simulation was effectively improved. The construction of the stress field was based on the combined spring model, as well as the data related to the measured in-situ stress and the formation pressure obtained during drilling. The coupling relationship between the in-situ stress, the formation strain, and the formation pressure were derived to carry out the prediction of the distributions of the formation pressure and the formation pressure coefficient. The prediction results showed that the present-day maximum principal stress direction in the study area was about NE65°–110°, and the present-day maximum principal stress was 56.12–93.79 MPa. The present-day minimum principal stress direction was about NE335°–20°, and the present-day minimum principal stress was 48.06–71.67 MPa. The formation pressure was 2.8–88.25 MPa, and the formation pressure coefficient was 0.74–1.55. The formation pressure distribution was greatly affected by fault, tectonic location, in-situ stress and rock petrophysical properties, and the overpressure areas of the formation were distributed in the synclines and the deeply buried areas. This study shows that the finite element based formation pressure prediction method is effective.

Dynamic Buckling Characteristics of Drill String in Horizontal Wells

Buckling may cause drill string damage or even drilling failure. For the 3[Formula: see text]000-m-long horizontal section drill string, a simplified analysis model of drill string in horizontal well is established, and the dynamic response results of axial displacement, angular displacement and contact force are obtained. When buckling, the closer the position of drill string is to the bottom, the later the buckling time, the smaller the buckling deformation degree, the slower the growth rate of axial displacement, and the smaller the attenuation degree of angular displacement and contact force amplitude. After buckling, drill string undergoes tensile deformation and eventually remains stable in the tensile state. After stabilization, from the top of drill string to the bottom of drill string, axial displacement increment increases first, then remains unchanged and then decreases, and the relative torsion angle between different positions gradually decreases. The drill string is always in horizontal contact with the wellbore, resulting in the same contact force values at different locations. The change of well inclination angle does not affect the change law of displacement and contact force. The absolute value of angular displacement is negatively correlated with the change of well inclination angle, and the value of axial displacement increment and contact force is positively correlated with the change of well deviation angle, but the value of contact force is quite close. The research results can provide reference for alleviating the buckling of drill string in horizontal wells.

Production prediction based on ASGA-XGBoost in shale gas reservoir

The advancement of horizontal drilling and hydraulic fracturing technologies has led to an increased significance of shale gas as a vital energy source. In the realm of oilfield development decisions, production forecast analysis stands as an essential aspect. Despite numerical simulation being a prevalent method for production prediction, its time-consuming nature is ill-suited for expeditious decision-making in oilfield development. Consequently, we present a data-driven model, ASGA-XGBoost, designed for rapid and precise forecasting of shale gas production from horizontally fractured wells. The central premise of ASGA-XGBoost entails the implementation of ASGA to optimize the hyperparameters of the XGBoost model, thereby enhancing its prediction performance. To assess the feasibility of the ASGA-XGBoost model, we employed a dataset comprising 250 samples, acquired by simulating shale gas multistage fractured horizontal well development through the use of CMG commercial numerical simulation software. Furthermore, XGBoost, GA-XGBoost, and ASGA-XGBoost models were trained using the data from the training set and employed to predict the 30-day cumulative gas production utilizing the data from the testing set. The outcomes demonstrate that the ASGA-XGBoost model yields the lowest mean absolute error and offers optimal performance in predicting the 30-day cumulative gas production. Additionally, the mean absolute error of the unoptimized XGBoost model is markedly greater than that of the optimized XGBoost model, indicating that the latter, refined through the application of intelligent optimization algorithms, exhibits superior performance. The insights gleaned from this investigation have the potential to inform the development of strategic plans for shale gas oilfields, ultimately promoting the cost-effective exploitation of this energy resource.

Experimental study on the mechanical controlling factors of fracture plugging strength for lost circulation control in shale gas reservoir

The geological conditions of shale reservoir present several unique challenges. These include the extensive development of multi-scale fractures, frequent losses during horizontal drilling, low success rates in plugging, and a tendency for the fracture plugging zone to experience repeated failures. Extensive analysis suggests that the weakening of the mechanical properties of shale fracture surfaces is the primary factor responsible for reducing the bearing capacity of the fracture plugging zone. To assess the influence of oil-based environments on the degradation of mechanical properties in shale fracture surfaces, rigorous mechanical property tests were conducted on shale samples subsequent to their exposure to various substances, including white oil, lye, and the filtrate of oil-based drilling fluid. The experimental results demonstrate that the average values of the elastic modulus and indwelling hardness of dry shale are 24.30 GPa and 0.64 GPa, respectively. Upon immersion in white oil, these values decrease to 22.42 GPa and 0.63 GPa, respectively. Additionally, the depth loss rates of dry shale and white oil-soaked shale are determined to be 57.12% and 61.96%, respectively, indicating an increased degree of fracturing on the shale surface. White oil, lye, and the filtrate of oil-based drilling fluid have demonstrated their capacity to reduce the friction coefficient of the shale surface. The average friction coefficients measured for white oil, lye, and oil-based drilling fluid are 0.80, 0.72, and 0.76, respectively, reflecting their individual weakening effects. Furthermore, it should be noted that the contact mode between the plugging materials and the fracture surface can also lead to a reduction in the friction coefficient between them. To enhance the bearing capacity of the plugging zone, a series of plugging experiments were conducted utilizing high-strength materials, high-friction materials, and nanomaterials. The selection of these materials was based on the understanding of the weakened mechanical properties of the fracture surface. The experimental results demonstrate that the reduced mechanical properties of the fracture surface can diminish the pressure-bearing capacity of the plugging zone. However, the implementation of high-strength materials, high-friction materials, and nanomaterials effectively enhances the pressure-bearing capacity of the plugging zone. The research findings offer valuable insights and guidance towards improving the sealing pressure capacity of shale fractures and effectively increasing the success rate of leakage control measures during shale drilling and completion.

Investigation on multiphase flow of multi-size cuttings particles and non-Newtonian drilling fluids in oil and gas horizontal well drilling using kinetic theory of granular flow

Effective cuttings transport has long been a challenge in oil and gas horizontal drilling, and inadequate wellbore cleaning can result in severe drilling accidents including stuck pipe. The transportation of multi-size cuttings by non-Newtonian drilling fluids in the horizontal wellbore with a rotating drill pipe was systematically investigated using the kinetic theory of granular flow. Collisions between particles and their two-way coupling with drilling fluid turbulence were modeled. Flow regime of multi-size cuttings has been predicted, and effects of particle size composition characteristics were studied. The spatial inhomogeneity of the non-Newtonian fluid viscosity and the sedimentation of particles result in a complex stratified flow regime for multi-size cuttings transport. Cuttings concentration and drilling fluid axial velocity distributions both show swaying phenomena with drill pipe rotation. Moreover, the secondary flow regions appear with negative tangential velocities. The cuttings transport ratio (CTR = 0.846) is the best in the case of cuttings with different particle sizes injected in a uniform concentration. While in the case where the concentration of injected multi-size cuttings is negatively correlated with particle size, the cuttings velocity fluctuations caused by collisions and frictions are the most severe, and the borehole cleaning is the worst (CTR = 0.803).

Experimental and numerical study of measuring in-situ stress in horizontal borehole by hydraulic fracturing method

Horizontal directional investigation is an alternative method different from traditional (vertical) geotechnical investigation, which can effectively reflect geological conditions along the axis and evaluate the engineering characteristics of tunnels in mountainous areas with super long distances and depths. However, the absence of effective methods to measure in-situ stress in horizontal boreholes hinders the promotion of horizontal directional investigation. This paper relies on the thorough horizontal directional drilling geotechnical investigation of the Tianshan Shengli tunnel in China, based on the method of hydraulic fracturing in-situ stress measurement, the relationship between the direction and magnitude of in-situ stresses and the parameters of the hydraulic fracturing was established in a horizontal borehole by enhancing the previous model of inclined boreholes. The interpretation principles of horizontal boreholes by hydraulic fracturing method are further explored through experimental and numerical study. The conclusion of this paper provides theoretical and empirical support for in-situ stress measurement in horizontal boreholes by hydraulic fracturing method.

An experimental study of Horizontal Directional Drilling (HDD) in sand in a large flexible calibration chamber

Horizontal Directional Drilling (HDD) is a trenchless technique for underground infrastructure installation that uses pressurized drilling fluid. Excessive loss of fluid to the formation can cause problems not only for the execution of HDD but also to nearby structures and must, therefore, be avoided. Hydraulic fracture is one of the possible causes and theories to predict the ultimate pressure have been developed, mostly for clays. Luger and Hergarden (1988, apud Keulen, 2001) developed a hydraulic fracture model particularly for HDD. The present study presents an experimental program carried out on a large flexible calibration chamber in sand using drilling fluid and confining pressures compatible with HDD field conditions. Results show that while local fracturing may occur, causing injection pressure to decrease for a while, permeability is still the dominating factor.

Prediction Model of Horizontal Drilling Trajectory of Anti-collision Drilling Robot

The horizontal drilling trajectory of the anti-collision drilling robot is taken as the research object and its drilling trajectory prediction model is established in this paper. The drilling trajectory is affected by many factors, such as the structural parameters of the auger, the drill bit, the drilling process parameters, and the geological characteristics of the coal seam, etc., which results in the existence of multi-level time-scale structure and localization characteristics of the drilling trajectory data in the time domain. The wavelet analysis method can decompose the relatively complex non-stationary time series problem into low-frequency decomposition signals representing trend items and high-frequency decomposition signals representing periodicity and randomness. It can not only predict the main trend of drilling trajectory changes but also effectively predict sudden load changes and short-term changes. Based on this, a new prediction method is proposed in this paper. Firstly, the data is decomposed into relatively simple component signals using wavelet decomposition technology, then the prediction models are established according to the characteristics of each component signal. Finally, the drilling trajectory prediction model is established by synthesizing the prediction results. The anti-impact drilling robot drilling test bed is set up and the drilling experiments are carried out to verify the effectiveness of the model, which can lay the foundation for the anti-impact drilling robot drilling deflection control.

Development of annular pump to enhance drilling distance and cuttings return in horizontal directional drilling

In many shallow horizontal directional drilling (HDD) projects, the annulus fluid pressure soon reaches the blowout or frac-out pressure of the soil formation. The pressure at single-source pump therefore must be limited. This limits the maximum drilling distance (borehole length), maximum attainable rate of penetration (ROP), and maximum distance over which cuttings can be returned. A novel concept involving a series of annular pumps distributed along the borehole length to aid in generation of distributed annulus pressure boost and cuttings transport in HDD was conceived. The success of the above concept, designated as distributed pumping system (DPS), relies on the ability to design and power an annular pump that can fit in the constricted annulus geometry of HDD boreholes while satisfying the performance requirements. We present the laboratory-scale development of three annular pumps based on the turbomachinery design principle of axial blade propellers. The pump prototypes were 3D printed and tested in the laboratory test rig flow loop built to simulate the annular flow configuration of HDD boreholes. The annular pump was powered using the axial propeller turbine housed inside the hub of each annular pump. The turbine converts hydraulic energy from the inner flow (analogous to drilling fluid flow within drill rod) to power the integrated setup of the axial inner turbine and annular pump, in short, designated as integrated turbine-pump (ITP). Results from the tests on three preliminary prototypes of the annular pump using water as the medium in the test rig yielded a maximum pressure boost of 44 kPa–enough to space the annular pumps 80 m apart when designed for a typical annular pressure drop rate of 0.54 kPa/m. The performance index (i) of the ITP, defined as the ratio of pressure boost provided by the annular pump in the outer (annular) flow to the pressure drop created by an inner turbine in the inner flow, reached a maximum value of 0.6. The results from the study promise a technology that can enable long-distance HDD cuttings return without the risk of blowout or the need for an external power source.

Hydrocarbon production induced land deformation over Permian Basin; analysis using persistent scatterer interferometry and numerical modeling

The Permian Basin, encompassing Southeastern New Mexico and Western Texas, has been an important source of oil and natural gas for over a century for the United States. With recent advancements in petroleum extraction methods, such as hydraulic fracturing and horizontal drilling, production has increased exponentially. Such rapid developments, along with the disposal of wastewater back into the subsurface, have caused significant changes in the stress regime of the region’s subsurface, resulting in various geohazards including land subsidence. In this work, we used the Sentinel-1C-band SAR dataset acquired between 2016 and 2021 to measure the basin-wide deformation over the entire Permian Basin. We utilized Persistent Scatterer Interferometry (PSI) technique to produce the time-series deformation at millimeter-level accuracy. The average monthly production and injection volumes and well depths over the Delaware Basin in New Mexico were calculated for each well and the impact of the hydrocarbon activities on the deformation was modeled using a distributed point source model from fluid volume and well depth data. The results show that the Permian Basin was deforming at a rate of 3–4 cm/yr., with two large pockets of deformation to the north of the Grisham Fault Zone (GFZ) in the Delaware Basin. The region south of the GFZ shows complex deformation features with linear patterns, indicating the presence of faults hindering fluid flow. Some areas in the Delaware Basin also show an uplift, especially along the Texas side of the border driven by shallow wastewater injection. The Midland Basin is also affected by subsidence with several localized subsidence zones identified in the region. Further, the Midland Basin experienced an increase in intensity and the spatial distribution of the deformation over the last few years. Given both production and injection well data, the modeled deformation results agree with the observed except in two pockets. When only production data is used for the modeling, the modeled deformation shows better agreement with the observed, especially in the interior of New Mexico. The modeling results suggest that the deep wastewater injection has minimal impact on surface deformation in the region. Additionally, it is also possible that the region has undergone inelastic deformation. While we used an elastic model in this preliminary study, a more accurate study requires regional poroelastic modeling to study the interaction between the solid subsurface and fluid hydrocarbons in detail.

An Overview of the Differential Carbonate Reservoir Characteristic and Exploitation Challenge in the Tarim Basin (NW China)

The largest marine carbonate oilfield and gas condensate field in China have been found in the Ordovician limestones in the central Tarim Basin. They are defined as large “layered” reef-shoal and karstic reservoirs. However, low and/or unstable oil/gas production has been a big challenge for effective exploitation in ultra-deep (>6000 m) reservoirs for more than 20 years. Together with the static and dynamic reservoir data, we have a review of the unconventional characteristics of the oil/gas fields in that: (1) the large area tight matrix reservoir (porosity less than 5%, permeability less than 0.2 mD) superimposed with localized fracture-cave reservoir (porosity > 5%, permeability > 2 mD); (2) complicated fluid distribution and unstable production without uniform oil/gas/water interface in an oil/gas field; (3) about 30% wells in fractured reservoirs support more than 80% production; (4) high production decline rate is over 20% per year with low recovery ratio. These data suggest that the “sweet spot” of the fractured reservoir rather than the matrix reservoir is the major drilling target for ultra-deep reservoir development. In the ultra-deep pre-Mesozoic reservoirs, further advances in horizontal drilling and large multiple fracturing techniques are needed for the economic exploitation of the matrix reservoirs, and seismic quantitative descriptions and horizontal drilling techniques across the fault zones are needed for oil/gas efficient development from the deeply fractured reservoirs.

Study on the Mechanism of High-Efficiency Rock Breaking by Hydraulic Jet Based on Explicit Dynamics

High-efficiency rock breaking by hydraulic jetting is the key to radial horizontal drilling technology. In order to improve the drilling efficiency of hydraulic jet rock breaking in radial horizontal wells, based on LS-Dyna display dynamics, a numerical simulation model of single-nozzle jet rock breaking was established to analyze the influence of different nozzle parameters on the rock-breaking effect. Then, the numerical simulation model of the spin multi-nozzle jet bit was established, and the influence of different rotation speeds on the rock-breaking effect of the jet bit was analyzed. Finally, the rock-breaking drilling characteristics of the spin multi-nozzle jet bit and the conventional multi-nozzle jet bit were compared and analyzed. The results show that when the jet impacts the rock surface, the larger the inclination angle is, the larger the rock-breaking width formed by the jet is. The smaller the dip angle, the greater the rock-breaking depth. When the inclination angle is greater than 60°, it is difficult to meet the needs of reaming. The width and depth of the nozzle gradually increase with the increase of the diameter. When the nozzle diameter is greater than 1.3 mm, the growth rate of rock-breaking depth begins to decrease. The optimum nozzle diameter is 1.3 mm. When v = 50 m/s, the damage caused by the jet to the rock surface is very small, because the condition of rock fracture is not reached with this velocity. This shows that there is a critical value of the water jet impact velocity, and only when the velocity is reached, will the rock break. When the velocity is v = 150 m/s, v = 200 m/s, v = 250 m/s, v = 300 m/s, the rock breaks. At the same time, the higher the speed, the higher the degree of rock fracture, the greater the fracture depth, the greater the fracture area, and the better the fracture effect. The tangential and radial velocity of the jet increases the shear and tensile failure rate of the sample, and improves the rock-breaking efficiency of the jet, which has a certain guiding significance for improving the rock-breaking drilling efficiency of radial horizontal well drilling.

Grand Challenges for the Oil and Gas Industry for the Next Decade and Beyond

_ The oil and gas industry faces a rapidly changing world of multiple challenges and opportunities, especially with growing climate and sustainability concerns. About a decade ago, SPE conducted a series of workshops to define the grand challenges in technology and R&D for the upstream oil and gas industry for the following decade. It identified 5 + 1 grand challenges (Table 1). To define the set of grand challenges for the next decade, in a much more unpredictable environment, we held an SPE workshop in Austin, Texas, in January 2023. Panelists from IOCs, NOCs, and service companies, as well as environmental and financial stakeholders in the emerging energy system, surveyed the rapidly changing energy landscape. The workshop then facilitated sessions of the more than 120 thought leader participants to define grand challenges that are impactful for society and our industry and have a significant R&D/technology component that is aligned with the capabilities of the SPE membership. We arrived at a list of five technical grand challenges: improved recovery from tight/shale resources, net-zero operations, carbon capture, utilization, and storage (CCUS), geothermal energy, and digital transformation. Additionally, we identified a sixth “bonus” nontechnical challenge—education and advocacy, since we believe that more effective engagement with thought leaders outside our industry will be required to advance and deploy new technologies in all five of these areas. Table 2 summarizes the technical challenges and their impacts. We believe that this work will help the industry focus its R&D and technology efforts on the highest-value activities for both industry and society. We now summarize each of these new grand challenges. Improved Recovery From Tight/Shale Resources Notwithstanding the rapid growth of non-hydrocarbon energy sources and carriers, oil and natural gas demand are projected to continue rising through 2050 (EIA 2023). In the past 20 years, horizontal drilling and hydraulic fracturing were combined to extract hydrocarbons from unconventional shale resources, which helped us meet rising global oil demand. However, production from existing shale oil wells declines quickly, and ultimate recoveries are often less than 10%. To meet global demand, we must improve recovery with minimal environmental impact. Tight and shale oil reservoirs have unique challenges. For example, shale reservoirs are subject to clay swelling and formation damage. Permeabilities are ultra-low, often on the order of nano-Darcys, which leads to extremely low flow rates and to transport dominated by diffusion. Thus, hydraulic and natural fractures are necessary, and geomechanics/rock compaction plays an important role. Many traditional improved oil recovery (IOR) strategies are challenging in tight and shale reservoirs. The small pores make waterflooding techniques difficult, and the low permeability hampers well-to-well methods. Thus, single-well, huff-and-puff strategies are the most common IOR methods. Injectants include miscible and immiscible gases (CO2, CH4, and N2) and chemicals (surfactants, solvents, and nanoparticles). In addition, thermal methods may allow control of oil viscosity and pressurization of the reservoir.

Comparative Study between Different Oil Production Enhancement Scenarios in an Iraqi Tight Oil Reservoir

This paper presents a comparative study between different oil production enhancement scenarios in the Saadi tight oil reservoir located in the Halfaya Iraqi oil field. The reservoir exhibits poor petrophysical characteristics, including medium pore size, low permeability (reaching zero in some areas), and high porosity of up to 25%. Previous stimulation techniques such as acid fracturing and matrix acidizing have yielded low oil production in this reservoir. Therefore, the feasibility of hydraulic fracturing stimulation and/or horizontal well drilling scenarios was assessed to increase the production rate. While horizontal drilling and hydraulic fracturing can improve well performance, they come with high costs, often accounting for up to 100% of the total well cost. To ensure economically viable flow rates and achieve maximum ultimate oil recovery, a technical and economic comparative study was conducted. The results indicate that hydraulic fracturing offers promising outcomes, with a total oil production of 153,816 Mbbl over 30 years from 25 fractured wells, resulting in a final Net Present Value (NPV) of 3,583.32 MM$. In contrast, the planned two horizontal wells exhibit lower eventual production and NPV compared to the majority of fractured wells. However, the 2000 m lateral section of well HF00Y-S00YH shows a slightly higher NPV. Considering the operational benefits and profitability, hydraulic fracturing should be seriously considered for the further development of the Saadi reservoir. This comparative study provides valuable insights into the most effective approach for enhancing oil production in tight reservoirs like Saadi, balancing the technical feasibility and economic viability of different stimulation scenarios. The findings can guide decision-making processes and contribute to maximizing oil recovery in similar challenging reservoirs.

The efficiency of the horizontal directional drilling method in the rehabilitation and modernization projects of the underground infrastructure

"The evolution of human society was and is dependent on natural resources (oil, natural gas, coal, ores, industrial water, drinking water, etc.) and, obviously, on their transportation through pipelines. The existence of resources in the earth's crust, at depths not always accessible, required the finding of methods for their exploration and exploitation. Consequently, in the last 30 years, drilling methods, techniques and technologies have been developed. Today, the Horizontal Directional Drilling method covers the entire geological spectrum, and in terms of rehabilitation and modernization projects of the underground infrastructure, it ensures high quality. Therefore, Horizontal Directional Drilling is the smart, clean and efficient solution for installing the network sections to be installed. The authors, under the auspices of the Romanian Academy of Technical Sciences (ASTR) and the General Association of Romanian Engineers (AGIR), in this paper, highlight the use and advantages of Horizontal Directional Drilling. The main objective is to install such services in Romania without using traditional trenching methods, helping to avoid any unnecessary impact on the environment and, evidently, offering extra security. "

Forecasting supercritical behavior of drill strings in horizontal wells

The determining factor in the current changes in the world energy balance and its structure, as well as the global development of the oil and gas industry, is currently the technological factor. As a result, fundamentally new categories of horizontal and inclined wells appeared and developed. They give a multiple increase in flow rates, as they increase the production area many times over. They are used in the development of offshore projects, in swampy and very difficult areas, to increase oil recovery, restoration of inactive wells.
 New technologies based on the method of horizontal drilling have revolutionized the practice and theory of world oil production, as they have allowed the destruction of offshore oil and gas fields without the construction of expensive offshore foundations and platforms.
 When drilling horizontal wells, as a rule, the main cause of emergencies is the loss of stability of the drill string, its bifurcation protrusion and the maximum frictional interaction with the well wall. The issues of theoretical modeling of the phenomenon of unstable protrusion of columns are associated with significant difficulties, the main of which is due to the need to set the Sturm-Liouville boundary value problem on a large length of drill string. Because for deep wells, the drill string becomes geometrically similar to a human hair, many traditional mathematical methods used to integrate solving equations become poorly convergent in these cases.
 Based on the theory of curvilinear flexible rods, the problem of theoretical modeling of supercritical states of drill strings taking into account their contact interaction with the walls of oil and gas wells is set. Analytical solutions of the problem are constructed, which determine the critical values of external tensile or compressive longitudinal force and torque at a given difference in the diameters of the cavity and the drill string, the zones of supercritical states of drill strings are established.

A Novel Model for the Real-Time Evaluation of Hole-Cleaning Conditions with Case Studies

The main challenge in deviated and horizontal well drilling is hole cleaning, which involves the removal of drill cuttings and maintaining a clean borehole. Insufficient hole cleaning can lead to issues such as stuck pipe incidents, lost circulation, slow rate of penetration (ROP), difficult tripping operations, poor cementing, and formation damage. Insufficient advancements in real-time drilling evaluation for complex wells can also lead to drilling troubles and an increase in drilling costs. Therefore, this study aimed to develop a model for the hole-cleaning index (HCI) that could be integrated into drilling operations to provide an automated and real-time evaluation of deviated- and horizontal-drilling hole cleaning based on hydraulic and mechanical drilling parameters and drilling fluid rheological properties. This HCI model was validated and tested in the field in 3 wells, as it was applied when drilling 12.25″ intermediate directional sections and an 8.5″ liner directional section. The integration of the HCI in Well-A and Well-B helped achieve much better well drilling performance (50% ROP enhancement) and mitigate potential problems such as pipe sticking due to hole cleaning and the slower rate of penetration. Moreover, the HCI model was also able to identify hole-cleaning efficiency during a stuck pipe issue in Well-C, which highlights its potential usage as a real-time model for optimizing drilling performance and demonstrates its versatility.

Sensitivity Analysis of Geomechanics Influence on The Success of Hydraulic Fracturing in Shale Gas Reservoir

Shale gas has a permeability of <0.1 mD and a porosity of around 2% - 8% to produce gas that rises to the surface through hydraulic fracturing and horizontal drilling. Geomechanics is one of the important factors that influence the success of a hydraulic fracturing job. Technology in fractures makes geomechanics a clear factor in predicting the success or failure of rocks in deformation and knowing the properties that will be faced by fracture fluids which will later be used to see the effectiveness of fracture fluids in resisting fractures. High operational costs need to be studied further to determine the parameters that affect hydraulic fracturing work, especially from the geomechanical aspect to minimize production failures and work safety. The research conducted this time focuses on the sensitivity of geomechanical parameters by using CMG (GEM) reservoir simulations for reservoir models and conducting Response Surface Methodology (RSM) in selection and ease when applied in the field prior to the hydraulic fracturing process. In this sensitivity study carried out on 5 parameters namely stress, Poisson's ratio, Young's modulus, biot coefficient, and pore pressure. The geomechanical parameter that has the most influence on hydraulic fracturing work based on the sensitivity results carried out through 500 data sets using the Analysis of Variance obtained R2 = 0.99 with the results based on the importance value of the pore pressure variable of 3.8. Then Young's modulus is 0.28, stress is 0.12, Poisson's ratio is 0.08, and biot coefficient is 0.04.

High‐Speed Data Communication for Oil and Natural Gas Drilling Based on Triboelectric Nanogenerator

AbstractTriboelectric nanogenerator‐based environmental energy harvesting technology is not only for the applications of the Internet of Things but also has a revolutionary impact on traditional industrial fields. Advanced oil and natural gas drilling technology, for example, horizontal drilling and hydraulic fracturing, has important environmental concerns about water and atmospheric pollution. High data transmission rates and visual and real‐time monitoring are considered potential solutions to avoid both economic and environmental problems. The current data transmission rate for oil and gas drilling is just 5–40 bits per second, despite commercial fifth generation (5G) and future sixth generation (6G) wireless communication technologies with data rates of 10–1000 gigabits per second. Herein, a self‐powered while‐drilling communications system based on a triboelectric nanogenerator is reported. The data transmission rate is three orders of magnitude higher than the traditional method. The free‐standing layered mode triboelectric nanogenerators (FS‐TENGs) can achieve fast information transfer using the harvested energy from the vibration of the pipe wall.

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.