Horizontal Drilling Operations Research Articles

A Comprehensive Geomechanical Study to Understand Drilling Challenges in the Eridu Oil Field, Southern of Iraq

In recent years, the Eridu oil field has emerged as a key player in the petroleum industry in southern Iraq as it is the biggest Iraqi oil discovery in 20 years. Extending along a vast area of 5806 km2, the field has commercial oil reserves in formations such as Mishrif, Nahr Umr, Zubair, and Yamama. However, drilling operations in this field have faced significant challenges, including delays and suspensions caused by wellbore instability. One of the main obstacles encountered during drilling operations in the Eridu oil field is the occurrence of partial losses in weak vugs dolomite formations, as well as issues related to sever borehole instabilities such as drilling in tight holes, caving, and breakout due to shear failure in the borehole wall. To address these challenges, a 1 D Geomechanical model (1-D MEM) was constructed using data from vertical wells to better understand the underlying causes of drilling problems. The findings of the 1-D MEM, particularly in relation to mechanical rock properties, rock Elasticity factors, pore pressure, and fracture gradient complex formations like Tanuma and Mishrif, were instrumented in planning drilling operations for inclined and highly deviated wells. By utilizing open hole well logging data and calibrating the model with various resources of data including drilling observations, core mechanical analyses, and pore pressure measurements, a more accurate assessment of wellbore instabilities was achieved. The analysis revealed that many of the wellbore instabilities, such as pack-off, breakout, and stuck pipe, were attributed to the insufficient mud weight that failed to support the rock in the borehole wall. To avoid these issues, it was determined that a safe mud weight range of 11-12.5 ppg is necessary to prevent wellbore instability in shale formations. The study also highlighted the importance of using proper mud weight to prevent shear failure and other drilling complications. The findings of this study provide insights that can be utilized as a cost-effective tool for planning directional and horizontal drilling operations in the Eridu oil field. The accuracy of the failure criteria and geomechanical model is significantly superior and aligns with the analysis of breakouts observed in the caliper and image logs.

Real‐time prediction of horizontal drilling pressure based on convolutional Transformer

SummaryDuring horizontal drilling operations, real‐time prediction of drilling pressure during the drilling process can help the drilling team cope with the complex and changing working environment downhole, adjust the parameters of the drilling rig promptly, make correct decisions, reduce the probability of drilling accidents, and avoid affecting the duration and cost of the project. This study provides a method for real‐time prediction of the drilling pressure of horizontal drilling rigs. A deep learning model based on a convolutional Transformer is trained for accurate real‐time prediction by extracting real‐time operating data of the horizontal drilling rig from the data acquisition system. The method proposed in this study can be a useful tool to improve the performance of horizontal drilling rigs and can assist the drilling team in operating horizontal drilling rigs. The results of the case study show that: (1) the proposed convolutional Transformer model provides reliable real‐time prediction with an MAE of 0.304 MPa and an RMSE of 0.508 MPa; (2) the proposed method can quickly and accurately predict the trend of drilling pressure change in the next period based on the current change of drilling pressure, and grasp the dynamics of drilling pressure of horizontal drilling rigs in advance. Further research could focus on assisted decision‐making and intelligent optimization to provide solutions for preventing drilling accidents and improving horizontal rig performance based on the prediction.

Field tests of high-density oil-based drilling fluid application in horizontal segment

The operational experience of a horizontal segment well within the hard brittle shale layer of Longmaxi Formation in the southern Sichuan area demonstrates that the high-density oil-based drilling fluid (HDOF) induced down-hole working conditions(high-temperature, high-pressure, and solid-phase-dominance)directly impact the stability of the wellbore wall. Focusing on the impact of bottom-hole osmotic pressure and solid phase content and a series of density-reduction field tests, we identified suitable countermeasures. In this paper, we discuss the impact of high osmotic pressure and operational measures, and provide details of the field tests, which indicate that maintaining a higher osmotic pressure at the bottom-hole can reduce the formation pore pressure of the bottom-hole, widen the fluid density window, and maintain the stability of the wellbore wall. By improving the HDOF formula, such as using new treatment agents (e.g., polymer-modified nano-sealing agent and ultra-micro barite weight additive) and optimizing the solid particle size distribution of HDOF, we can effectively address the down-hole problems. The field test of “pressure-controlled drilling + density reduction” in horizontal drilling operations was found to reduce the complexity of down-hole faults, improve the rate of penetration, and reduce overall costs.

Experimental investigation of cuttings transport with nanocomposite water-based drilling fluids modified by cellulose nanoparticles

Extended reach (ERD) wells with a horizontal and highly deviated section are commonly utilized in deep oil and natural gas exploration operations. Among many difficulties faced in this complex wellbore trajectory, good hole cleaning is one of the biggest challenges. The main objective of the present study is to investigate the application of cellulose nanoparticles (CNPs) in improving hole cleaning in horizontal drilling operations. Nanocomposite drilling fluids were prepared by adding CNPs, including cellulose nanocrystals (CNCs) and cellulose nanofibers (CNFs), into water-based mud (WBM) at different weight percent concentrations (0.15–0.60 wt%). The flow loop experiments were implemented on a sophisticated purpose-built flow rig by circulating the tested fluid samples into the test section in a horizontal position, considering the influence of drill pipe rotation, flow rates, cuttings sizes, and drill pipe eccentricity. The goal of such variation in the operational parameters is to simulate real field conditions. The cuttings transport ratio (CTR) which is defined as the ratio of the weight of recovered cuttings to the weight of injected cuttings is chosen as the measurement to evaluate hole cleaning. The results revealed that the nanocomposite drilling fluids displayed a considerable enhancement in cuttings removal efficiency, especially with the higher concentration of CNPs. The morphology of CNPs played a vital role in improving the rheological properties of the water-based drilling fluids. In comparison, the drilling fluid samples with CNCs had comparatively lower cuttings transports ratio (CTR) than these of the fluids with CNFs. These differences were connected to their distinguished morphologies and different interactions with bentonite in the fluid system. This work is the first attempt to evaluate the applications of renewable, biodegradable, environmentally friendly, and more cost-effective nanoparticle additives to enhance the capability of drilling fluids in transporting and circulating drilled cuttings out of the wellbore.

A Perturbation Method to Model Electromagnetic Well-Logging Tools in Curved Boreholes

Logging-while-drilling (LWD) or measuring-while-drilling tools are routinely used to guide well placement during exploration of hydrocarbons reservoirs. These tools have become fundamental for directional and horizontal drilling operations. In this paper, we present a perturbation method to model electromagnetic fields produced by time-harmonic sources in radially stratified and axially toroidal structures describing LWD tools inside curved boreholes (i.e., boreholes with axial bending). The proposed formulation is validated against brute-force finite-difference results in various representative scenarios. Numerical results indicate that the proposed perturbative approach can provide a reduction in the computational effort required to analyze this class of problems of several orders of magnitude versus brute-force approaches.

Theoretical modeling of Positive Displacement Motors performance

Positive Displacement Motor (PDM) has been used extensively in directional and horizontal drilling operations. To the best of our knowledge, there is no reliable analytical model to predict the performance of PDMs. Based on motor geometry; each PDM has its own unique performance that is experimentally obtained by manufacturers using water as a testing fluid. These experiments are not only costly and time-consuming, but also with conditions that do not represent the actual down-hole conditions.The key to improve the prediction of motor performance is to, accurately; determine the flowing cross-sectional area of PDM. This paper uses Nguyen et al. (2014) model for calculating flow area of a multi-lobe progressing cavity pump, in addition to two developed analytical models for predicting the actual performance of a multi-lobe PDM. A sensitivity analysis was performed to optimize motor geometry to maximize motor torque. The developed models were validated using experimental data from a single 1:2-lobe and multi 2:3-lobe PDMs. The results revealed that when the stator lobe number is greater than five, torque is maximized if the dimensionless motor geometry is zero. The flowing cross-sectional area is reduced when the stator lobe number is higher than four lobes. However, the flow rate is always higher when the stator lobe number is increased. The results also showed that it is not recommended designing a PDM which has the stator lobe greater than twelve. Furthermore, model validation showed that the proposed model predicts the actual multi-lobe PDM performance with average percent error of less than 6% when differential pressure across the motor is 300 psi or less. The results of this study are not only important for manufacturers to optimize PDM design, but also for operators to improve the performance and efficiency of PDMs.

Investigating the impact of drillpipe's rotation and eccentricity on cuttings transport phenomenon in various horizontal annuluses using computational fluid dynamics (CFD)

Drillpipe eccentricity is a common issue in horizontal drilling operations. The eccentricity is a non-manipulative parameter by itself but its impact is a function of various parameters such as rate of penetration (ROP), fluid flow rate (Q), cuttings bed height, wellbore path and drillpipe rotation. The goal of this study is to observe the cutting's accumulation in different eccentric annuluses by employing a multiphase Eulerian flow model including a Herschel-Bulkley drilling fluid. Turbulence was implemented using Reynolds Stress Model which reveals proper results, especially on asymmetric and complex cases. All of these are developed and calculated through a comprehensive Computational Fluid Dynamics (CFD) simulations to solve the governing equations in the multiphase medium. A sensitivity analyzes were implemented from concentric to 75% eccentric cases accompanying different variations of fluid flow rate, ROP, and drillpipe rotation. The results demonstrated that further eccentricity from a certain amount will abruptly increase the cutting's accumulation which is a function of bed height, ROP/Q, and drillpipe rotation. However, rotation's impact is negligible above a certain speed of rotation after which the sudden increase of cutting's accumulation caused by eccentricity is not observable.

Nonlinear Drillstring-Dynamics Modeling of Induced Vibrations in Unconventional Horizontals

SummaryInducing vibrations while drilling is a relatively new concept that shows promise in directional applications. Instigating motion of the drillstring, particularly in the sections lying on the low-side of the wellbore, can lead to substantial improvements in managing the two limiting factors of the long horizontal wells that are typically associated with current unconventional shale plays: removal of formation cuttings from the borehole and frictional drag between nonrotating drillstrings and the wellbore wall. Minimizing these effects by introducing controlled vibrations increases the overall drilling efficiency and reduces the cost associated with the well. The difficulty in implementing such actions, however, is consistency. Because the behavior of drilling assemblies is inherently nonlinear, it has been difficult in the past to reliably predict their response to dynamic events. This, in turn, creates a challenge when trying to optimize the performance of arbitrary vibration-inducing devices (VIDs).This study presents a detailed analysis of the fully coupled, 3D, nonlinear behavior of drillstrings under the action of induced vibrations. Specific focus is given to the dynamic characteristics of a drillstring, during horizontal-drilling operations, in long unconventional wells and how this behavior affects the success of the well. The response of the drillstring, due to induced axial and lateral oscillatory motions, is examined through linearized dynamic analysis and nonlinear time-domain simulations.Solutions obtained from the study provide a clearer understanding of the dynamics experienced downhole and lead to suggestions for improved practices when drilling with lateral VIDs, particularly with regard to hole cleaning. Further insights into the sliding behavior of the drillstring, during the use of these types of tools, are drawn from animated modeling results. Finally, the future applications of this technology are discussed.

Effect of Drillstring Deflection and Rotary Speed on Annular Frictional Pressure Losses

Keeping the drilling fluid equivalent circulating density in the operating window between the pore and fracture pressure is a challenge, particularly when the gap between these two is narrow, such as in offshore, extended reach, and slim hole drilling applications usually encountered in shale gas and/or oil drilling. To overcome this challenge, accurate estimation of frictional pressure loss in the annulus is essential. A better estimation of frictional pressure losses will enable improved well control, optimized bit hydraulics, a better drilling fluid program, and pump selection. Field and experimental measurements show that pressure loss in annuli is strongly affected by the pipe rotation and eccentricity. The major focus of this project is on a horizontal well setup with drillstring under compression, considering the influence of rotation on frictional pressure losses of yield power law fluids. The test matrix includes flow through the annulus for various buckling modes with and without the rotation of the inner pipe. Sinusoidal, helical, and transition from sinusoidal to helical configurations with and without the drillstring rotation were investigated. Helical configurations with two different pitch lengths are compared. Eight yield power law fluids are tested and consistent results are observed. The drillstring rotation patterns and buckling can be observed due to experimental facility's relatively longer and transparent test section. At the initial position, inner pipe is lying at the bottom due to its extensive length, suggesting a fully eccentric annular geometry. When the drillstring is rotated, whirling, snaking, irregular motions are observed. This state is considered as a free drillstring configuration since there is no prefixed eccentricity imposed on the drillstring. The reason for such design is to simulate the actual drilling operations, especially the highly inclined and horizontal drilling operations. Results show that rotating the drillstring can either increase or decrease the frictional pressure losses. The most pronounced effect of rotation is observed in the transition region from laminar to turbulent flow. The experiments with the buckled drillstring showed significantly reduced frictional pressure losses compared to the free drillstring configuration. Decreasing the length of the pitch caused a further reduction in pressure losses. Using the experimental database, turbulent friction factors for buckled and rotating drillstrings are presented. The drilling industry has recently been involved in incidents that show the need for critical improvements for evaluating and avoiding risks in oil/gas drilling. The information obtained from this study can be used to improve the control of bottomhole pressures during extended reach, horizontal, managed pressure, offshore, and slim hole drilling applications. This will lead to improved safety and enhanced optimization of drilling operations.

Evolution of multi-well pad development and influence of well pads on environmental violations and wastewater volumes in the Marcellus shale (USA)

A majority of well pads for unconventional gas wells that are drilled into the Marcellus shale (northeastern USA) consist of multiple wells (in some cases as many as 12 wells per pad), yet the influence of the evolution of well pad development on the extent of environmental violations and wastewater production is unknown. Although the development of multi-well pads (MWP) at the expense of single well pads (SWP) has been mostly driven by economic factors, the concentrated nature of drilling activities from hydraulic fracturing and horizontal drilling operations on MWP suggests that MWP may create less surface disturbance, produce more volumes of wastewater, and generate more environmental violations than SWP. To explore these hypotheses, we use geospatial techniques and statistical analyses (i.e., regression and Mann–Whitney tests) to assess development of unconventional shale gas wells, and quantify environmental violations and wastewater volumes on SWP and MWP in Pennsylvania. The analyses include assessments of the influence of different types of well pads on potential, minor and major environmental events. Results reveal that (a) in recent years, a majority of pads on which new wells for unconventional gas were drilled are MWP, (b) on average, MWP have about five wells located on each pad and thus, had the transition to MWP not occurred, between two and four times as much land surface disturbance would have occurred per year if drilling was relegated to SWP, (c) there were more environmental violations on MWP than SWP, but when the number of wells were taken into account, fewer environmental violations per well were observed on MWP than on SWP, (d) there were more wastewater and recycled wastewater volumes per pad and per well produced on MWP than on SWP, and (e) the proportion of wastewater that was recycled was higher on MWP than SWP. This study sheds light on how the evolution from SWP to MWP has influenced environmental violations and wastewater production in a field that has undergone rapid development in recent years.

Experimental Feasibility of the In-Drilling Alignment Method for Inertial Navigation in Measurement-While-Drilling

Conventional methods in horizontal drilling processes incorporate magnetic surveying techniques for determining the position and attitude of the bottom-hole assembly (BHA). This results in an increased weight of the drilling assembly, higher cost due to the use of nonmagnetic drill collars necessary for shielding the magnetometers, and significant errors in the position of the drilling bit. A novel inertial navigation system (INS)-based technique has been previously proposed as an alternative to magnetometer-based downhole surveying. Previous studies have shown theoretically that an adaptive-filter-based in-drilling alignment (IDA) fine alignment method successfully limits the error growth associated with INS. This study aims at examining IDA's practical feasibility and, specifically, its ability to estimate the azimuth angle. Experimental testing of the IDA method was conducted under laboratory conditions with an apparatus that can easily be adopted for downhole conditions. The experimental results demonstrate that the IDA-estimated azimuth is more precise, compared with the one estimated by conventional magnetic surveying systems. The high accuracy and implementation simplicity of the proposed INS-based surveying system render it a preferred method for future horizontal drilling operations.

Use of Compressed Air-Blow Method in Horizontal Drilling Operations in Subsurface Soft Rocks.

Use of Compressed Air-Blow Method in Horizontal Drilling Operations in Subsurface Soft Rocks.

アブダビ石油における水平掘りについて

Abu Dhabi Oil Co., Ltd. (ADOC) is currently operating the following three oil fields; Mubarraz, Umm Al-Anbar (AR) and Neewat Al-Ghalan (GA) Field. A total of 73 wells have been drilled in our fields since MR-1 was drilled as a wild cat well in 1969. Furthermore, a total of 23 re-entry horizontal drilling operations from existing wells have been carried out, in order to increase the rate of oil production and oil recovery since 1996. Drilling operations have improved dramatically due to improvements in various aspects such as drilling technology, drilling mud technology and cementing technology which have contributed to more efficient and reliable drilling operations and subsequently better production history. This paper presents ADOC's drilling operation with an emphasis on re-entry horizontal drilling, including well trajectory, drilling assembly, drilling bit, drilling mud, re-entry method and running and cementing of the production liner.

The Andrew Formation and ‘biosteering’ — different reservoirs, different approaches

Abstract Biosteering, the provision of real-time biostratigraphic data for the drilling of horizontal wells, has developed and evolved a wide range of approaches and applications in recent years. Its value to the success of a development project has grown beyond its core role as an effective and rapid method by which to define the relative stratigraphic position of the drill bit for steering purposes. High-resolution biostratigraphy and biosteering are now being used as part of an integrated service which is being incorprated in the planning of a horizontal drilling programme and individual well paths. This paper illustrates some of this diversity of applications by describing two very different styles of biosteering from age-equivalent turbidite sands of the Andrew Formation, on the United Kingdom continental shelf (UKCS). The first example describes biosteering through thin (10–15 ft) turbidite sands from the Joanne Field. The reservoir is one of several thin allochthonous sand and limestone subunits, requiring a very detailed biostratigraphic framework to provide sufficient resolution to identify each of the subunits. The framework utilizes both in situ and derived/reworked assemblages and associations (microfacies) to identify up to 10 discrete and correlative lithostratigraphic subunits. Local dip variations, faults of subseismic resolution and thinness of sand hampered efforts to continuously remain within the reservoir during horizontal drilling operations. Well-site micropalaeontological interpretation correctly identified the position of the drill bit in relation to the reservoir sand, allowing the correct well-path deviation to be enacted. In the absence of this technique, hundreds of feet of additional non-reservoir section would have been drilled. The second example describes the Andrew Field, again comprising deep-marine turbidite sandstones of the Andrew Formation. Development of the Andrew Field has incorporated both the biosteering function of well-site biostratigraphy as well as pre-drill, high-resolution facies analysis of the microfaunas to assist in depositional modelling of the field. Microfacies analysis provides data relating to the potential sealing qualities and lateral continuity of adjacent silt and claystones, and how these may act as barriers or baffles during production. This information is utilized in the planning of the well path to optimize production through well placement and stand-off from oil-water and gas-oil contacts, and at the well site during horizontal drilling to confirm, through micropalaeontological analysis, key horizons at which to geosteer.

Horizontal Drilling Techniques at Prudhoe Bay, Alaska

Summary Three extended-departure horizontal wells have been drilled and completed in the Prudhoe Bay Unit, AK, by Standard Alaska Production Co. Horizontal slotted-liner completions of 1,575, 1,637, and 1,163 ft [480, 499, and 354 m] were achieved at an average vertical depth of 9,000 ft [2743 m]i. Over the three-well program, improvements in technology and operating procedures have resulted in a 40% reduction in cost per foot. When compared to conventional completions, production data from the horizontal wells indicated rate benefits up to 300% and a potential increase in ultimate recovery. This paper discusses the development of the techniques used to drill horizontal wells at Prudhoe Bay and reviews the horizontal drilling operations for each well. Introduction The application of horizontal drilling to the Prudhoe Bay field is driven by the goal of increasing ultimate field recovery. Conventional recovery methods are expected to leave an estimated 12 billion bbl [19 Gm3] of oil in place. Horizontal drilling in areas with gas and water coning potential and in regions of uneconomic oil column thickness was viewed as a potential method to maintain Prudhoe production levels and to increase ultimate recovery. In the midfield area at Prudhoe Bay (Fig. 1), the oil column lies between an expanding gas cap and a water leg. Throughout the production life of a well, high formation permeability allows production life of a well, high formation permeability allows increasing gas and water fractions because of coning. The overall production rate of the field will eventually be limited by the gas production rate of the field will eventually be limited by the gas handling capacity because the produced gas and water must be reinjected. A horizontal completion, strategically placed between the gas cap and water leg, will allow increased production rates at lower drawdown pressures and, consequently, will reduce gas and water coning tendencies. In the southwestern portion of the field where the oil column is less than 100 ft [30 m] thick, development using conventional wells is hindered by economic considerations. Because the gas cap is absent in this area, horizontal wells can be drilled along the top of the oil zone to expose longer reservoir sections that provide economical production rates while minimizing water production. In Jan. 1984, Standard Oil Production Co. began work on a project to develop the technology to drill and to complete horizontal project to develop the technology to drill and to complete horizontal wells at Prudhoe Bay. The strategy chosen was to drill a test well in south Texas to provide a technical basis, followed by three Prudhoe Bay wells to optimize the drilling techniques. To maximize the Prudhoe Bay wells to optimize the drilling techniques. To maximize the transfer of technology, drilling supervisors and a geologist from Standard's Alaska staff were assigned to the test well. Key individuals of the team that had drilled four successful horizontal wells in Europe were employed as consultants. The south Texas test well, Braune-Wieding No. 1, was designed to model closely the proposed Prudhoe Bay horizontal well profile. A 1,900-ft [579-m] horizontal section (inclination greater profile. A 1,900-ft [579-m] horizontal section (inclination greater than 84 degrees) was successfully placed in a 30- to 40-ft [9- to 12-m] -thick sand near 10,300 vertical ft (3140 m]. The well established and verified several planning and operational techniques. A top-drive system proved beneficial in dealing with anticipated directional drilling conditions, especially tight hole problems. Using, this system, two o three connections were eliminated and back-reaming while circulating 90-ft [27-m] sections was possible. To maximize torque available at the bit, a torque/drag simulator was used to design the wellbore profile and drillstring configuration. Experience was gained in high-angle directional drilling using steerable mud motors and conventional rotary assemblies. Measurement-while-drilling (MWD) systems were used extensively and proved indispensable for directional surveying and formation identification using gamma ray and resistivity sensors. Geologic markers were used to adjust and refine the directional profile continually while building angle to horizontal. Wellbore stability was a critical consideration in the high-angle sections of the well, and invaluable experience was gained in maintaining stability with high-weight, low-fluid-loss drilling fluids. Adequate hole cleaning was achieved with optimal mud properties and efficient solids removal equipment. The well was properties and efficient solids removal equipment. The well was logged with drillpipe-conveyed tools and completed using a slotted liner placed through the entire horizontal section. The completion incorporated a specially built liner hanger/packer and a circulating string that permitted drilling fluid displacement from the slotted liner.

Application of Recently Developed Medium-Curvature Horizontal-Drilling Technology in the Spraberry Trend Area

Recently developed horizontal-drilling techniques have been applied in the Spraberry trend area in Midland County, TX. The desired application includes drilling horizontally at a right angle to the naturally occurring vertical fractures in one of three Spraberry zones. The result was 1,180 ft (360 m) of vertical section within 10/sup 0/ (0.17 rad) of the planned azimuth of 115/sup 0/ (2.01 rad). The W.M. Schrock 38 No. 7 was drilled vertically to 8,620 ft (8,620 ft (2627 m) through the Upper Spraberry, Lower Spraberry, and Dean formations. After the curved portion of the hole had been drilled, 3- and 1/sup 0//100-ft (1.7 x 10/sup -3/ and 0.57 x 10/sup -3/-rad/m) motors were used in both rotational and orienting modes to maintain the inclination near 90/sup 0/ (1.6 rad) and in azimuth of about 115/sup 0/ (2.01 rad). During drilling at 8,598-ft (2621-m) measured depth (MD), the motor parted and and fishing job in the near-horizontal portion of the wellbore resulted. The motor and bit were successfully retrieved on the first attempt. From 8,400 to 8,835-ft (2560- to 2693-m) MD, inclination decreased from 90 to 82/sup 0/ (1.6 to 1.4 rad), resulting in the penetration of the base of the Lowermore » Spraberry. Drilling operations ceased at 7,929-ft (2417-m) TVD and 8,930-ft (2722-m) MD with 891 ft (272 m) of formation exposed vs. a 70-ft (21-m) exposure in a standard vertical-well completion in the Spraberry trend area.« less