Wellbore Inclination Research Articles

Migration characteristics of bubbles moving in gas–liquid countercurrent two-phase flow in an inclined pipe

While exploring and developing oil and gas, well kick and overflow accidents are inevitable. In such an accident, if the drilling bit is not at the bottom of the well, the drilling tool is blocked, or the reservoir contains toxic gases such as hydrogen sulfide, the traditional technique for well control is no longer suitable, and the bullheading method must be adopted to kill the well. However, during bullheading, the flow patterns of gas and liquid are intricate, making gas velocity hard to predict. To solve these problems, a set of visual simulation experimental device for directional well bullheading was built to find out the effects of wellbore inclination, liquid viscosity, gas and liquid velocities, and bubble size on bubble migration characteristics in gas–liquid countercurrent (gas flowing in opposite direction to the liquid). Prediction models of bubble distribution coefficient and rising velocity considering liquid viscosity, bubble size, and wellbore inclination angle were worked out. The experimental results show that small bubbles are mainly located in the center of the wellbore and large bubbles tend to approach the wellbore wall in gas–liquid countercurrent. Increasing wellbore inclination, viscosity, and the velocity of the liquid flowing against the bubbles results in a gradual decrease in Taylor bubble migration speed, which promotes the bubbles' pressing-back, as inhibiting the upward movement of large bubbles is essential for effective bullheading operations. The prediction models of distribution coefficient and bubble migration velocity have an error of less than 10% and 9. 78%, respectively.

Study on the Gas Phase Liquid Carrying Velocity of Deep Coalbed Gas Well with Atomization Assisted Production

In order to clarify the gas-phase carrying capacity after the atomization of water from the bottom of deep coalbed wells, considering characteristics of atomization-assisted production and the dynamic equilibrium principle of gas–liquid two-phase flow in the wellbore, the gas-phase liquid-carrying drop model was established, and the solution method of the upstream and downstream driving force of liquid drop flow was studied. We also verified the theoretical model through physical simulation. Then, the law for the influence of droplet size, wellbore inclination, wellbore diameter, and wellhead back pressure of the critical liquid-carrying velocity in the gas phase is analyzed using the model. The results show the following: ① the larger the diameter of atomized droplets, the greater the gravity force applied to it, the worse the ability to be carried by the gas phase, a onefold increase in droplet diameter corresponds to the increase in the minimum critical velocity of the gas phase by 1.45 times; ② with the increase in wellbore inclination, the liquid-carrying capacity of the gas phase decreases, and the minimum critical liquid-carrying velocity of equal diameter droplets increases by 0.01438 m/s or 1.27 times for the increase in wellbore inclination by 10°; ③ with the increase in wellbore diameter, both the driving force of a droplet of equal diameter and the flow resistance through the gas phase in the wellbore decrease within the range of a driving pressure difference of 0.2 Mpa; the decrease in liquid-carrying velocity caused by the decrease in received flow resistance can reach the maximum value of 0.0473 m/s; ④ with the increase in wellhead back pressure, the driving force of equal-diameter droplets decreases, the resistance against passing through the high-concentration gas phase increases, and the gas-phase-carrying droplets start the game; ⑤ the atomization-assisted production has the function of drainage gas recovery, and the adoption of atomization-assisted production technology can increase the production time of a coalbed gas flowing well, enabling the wells to have a good transition time interval for the conversion of flowing wells to pumping ones, which provides a precise production dynamic basis for the efficient design and implements the overall strategy of drainage gas recovery by deep-well pumping. In short, this technology has the high-efficiency liquid-carrying function of “water atomization to help liquid-phase flow and increase gas production”, as well as obvious technical advantages, which can provide a new idea for the development of deep coalbed methane wells and other types of gas wells with water.

Optimizing the Influence of Fly Ash as an Anti-Sagging Additive in Highly Deviated Geothermal Well Drilling Fluids Using Surface Response Method

Weighting materials such as barite and ilmenite are crucial for controlling fluid density during deep or ultra-deep drilling operations. However, sagging poses significant challenges, especially in highly deviated high-pressure and high-temperature (HP/HT) wells. This leads to inadequate well control, wellbore instability, and variations in hydrostatic pressure in extended-reach wells. Given the challenges of experimental research, reliable prediction models are imperative for evaluating the interaction between the ratio of anti-sagging additives, temperature, and wellbore inclination on sag factor (SF). This research presents statistical-based empirical models for predicting the SF at various wellbore inclinations (0°, 30°, 45°, 60°, 70°, 80°, and 90°) and assessing the influence of fly ash on the SF. The regression equations, developed using the Response Surface Methodology in Minitab 18 software, show high reliability, with R2 values approaching unity. Contour and surface response plots provide a clear understanding of the variable interactions. The analysis reveals that sagging is most severe at 60° to 65° inclination. At 400 °F and 60° inclination, adding 4 lb/bbl of fly ash reduces sagging in barite and ilmenite-densified fluid by 63.9% and 63.1%, respectively. Model validation shows high accuracy, with percentage errors below 3%. This study offers valuable insights for optimizing drilling fluid formulations in HP/HT well environments.

Vibration characteristics and safety analysis of production string in high temperature, high pressure gas wells

During the production of high-temperature, high-pressure (HPHT) gas wells, the gas entering the production tubing column induces vibration, which in turn leads to changes in the mechanical properties and safety of the tubing column. A dynamic model of the production string in an HPHT gas well was established to study the dynamic characteristics of its production string. The additional axial force caused by the transient temperature change and the nonlinear contact collision between the production string and the casing were considered. The Newmark-β method was used to solve the problem by analyzing and comparing the flow-induced vibration characteristics of the production pipe string. In this study, a gas well in the southwest Sichuan Basin was used as the research object to study the effects of gas production, packer setting position, and string wall thickness on the dynamic characteristics of the string. The results show that in the gas production process, intense vibrations are generated in the transverse and longitudinal directions of the tubular column. After high-velocity gas flows through the production tubing column, the vibrations at the wellbore inclination and the top of the tubing column are more intense. With the rise of production and the downward movement of the packer setting position, the vibration displacement and frequency of the tubing column increase. In addition, as the column's wall thickness increases, the column's stiffness rises, which, in turn, reduces the vibration of the column. When the gas production increases from 60 × 104 m3/d to 150 × 104 m3/d, the maximum transverse vibration displacement of the production string will increase by 22.2%–39.3%, while the frequency will increase by 15.3%–54.3%. When the wall thickness of the pipe column reaches 9.53 mm and 10.92 mm, it can be employed to enhance the safety factor of the string and extend the fatigue life of the string. This study provides a theoretical framework for field string protection and production guidance.

Sensitivity Analysis and Comparative Study for Different Detection Modes of Logging-While-Drilling Ultradeep Azimuthal Electromagnetic Tools

Summary The logging-while-drilling (LWD) ultradeep azimuthal electromagnetic tool plays a pivotal role in real-time drilling optimization operations. Established tool designs include arrays of coaxial and tilted coils that, during drilling operations, can be processed to a multicomponent magnetic induction data. These data can then be combined into different detection modes, which accentuate sensitivity to particular geological features. Leveraging the established coil design and definitions of various detection modes for an electromagnetic look-ahead (EMLA) tool, this study undertakes a comprehensive exploration of the disparities in detection performance and characterization of subsurface parameters. Through sensitivity analysis, the varying degrees of sensitivity exhibited by these detection modes concerning parameters such as subsurface formation resistivity, formation inclination, and electrical anisotropy have been investigated. The ensuing conclusions derived from an in-depth analysis are as follows: Detection Mode I exhibits remarkable prowess in delineating subsurface boundaries. Optimal exploration distances can be achieved through the judicious selection of source-receiver distances and frequencies. Detection Mode II displays heightened sensitivity to wellbore inclination and anisotropy, effectively elucidating subsurface resistivity anisotropy. This sensitivity is particularly pronounced at wellbore inclinations approaching 60°. Detection Mode III, while lacking directional capability, nonetheless furnishes fundamental insights into subsurface resistivity. Detection Mode IV demonstrates exceptional sensitivity to electrical anisotropy, particularly at higher wellbore inclinations, manifesting a conspicuous response to subsurface resistivity anisotropy. In summary, the diverse detection modes within the realm of ultradeep azimuthal electromagnetic technology each offer distinctive attributes, facilitating optimal mode selection to attain superior outcomes as per specific requisites. This research contributes significantly to an enhanced comprehension of the performance and applicability of the ultradeep azimuthal electromagnetic tool in the field of optimal drilling.

A new optimized method in wellbore to improve gas recovery in shale reservoirs

With the scale development of shale gas, the importance of selecting appropriate deliquification process has become increasingly evident in maintaining well productivity and improving shale gas recovery rate. At present, the preferred deliquification process are macro-control plate method and field experience method. The existing methods can only qualitatively select the deliquification process by considering limited influencing factors, resulting in poor process implementation. Based on the results of error analysis, the Gray model was optimized to calculate the pressure distribution in the shale gas wellbore and determine the applicable pressure limit. The W.Z.B. empirical model, which fully considers the influence of wellbore inclination, is used to calculate the gas-liquid carrying situation and determine the applicable liquid carrying limit. By analyzing the technical limits of five commonly used deliquification processes in the Changning shale gas field, namely, plunger lift, optimizing pipe string, gas lift, foam drainage, and intermittent production, a quantitative optimization method for deliquification processes was established. This method was then used to obtain the optimization chart for deliquification processes in shale gas wells. This method was applied in Well Ning 209-X, where the corresponding optimization chart for deliquification processes was drawn based on the production characteristics of the gas well. By quantitatively optimizing the deliquification processes and adjusting to suitable techniques, it effectively guided the production of the gas well and improved the gas field recovery rate.

The radial distribution of natural fracture density around the wellbore during drilled cuttings/produced water reinjection and well construction

Drilled cuttings or produced water reinjection, drilling operations, and even wellbore stimulation are operations that can exploit the knowledge of natural fractures around wellbores. However, there is currently no robust model that quantifies Natural Fracture Density (NFD) around wellbores, to manage the highlighted operations. This is a problem when one considers environmental pollution caused by drilling waste leakage through natural fractures. During wellbore construction, natural fractures may enhance lost circulation, which causes well-control problems. Existing predictive models cannot quantify the NFD (which is in units of count per meter) around the wellbore because of the limitations in handling the total strain. Hence, it becomes difficult to understand how geomechanical parameters, wellbore geometry, or petrophysical variables affect the NFD. Thus, this study was carried out to eliminate these gaps. The strain energy of poroelastic rocks, fracture-area energy, and geomechanical analysis were combined to quantify the NFD. The total strain was decomposed into deviatory strain and volumetric strain, using the principal stresses. Then, based on geomechanical analysis, the tangential, axial, and radial stresses were incorporated, using Kirsch's wellbore stresses. The model was applied to a wellbore that is near the Atlantic Ocean, on the passive continental margin of the Niger Delta Basin, and comprising paralic sandstones of the Miocene. The results showed that the NFD decreased from the walls of the wellbore exponentially. Increasing the wellbore inclination reduced the NFD, but the increase in porosity caused the NFD to increase. The increase in Poisson's Ratio (PR) showed a different relationship with the NFD. The NFD reduced slightly as PR was increased from 0 to 0.2, but increased significantly as PR was increased from 0.2 to 0.5. In addition, the NFD oscillated sinusoidally with the azimuth, at some frequency. The results were validated by different literature sources and field observations.

Lost circulation material design for near-wellbore transverse fractures

The use of particulate lost circulation material (LCM) in drilling fluid is a common method for mitigating lost circulation from near-wellbore fractures that develop during subterranean drilling. Fracture width estimation is the center piece of designing the particle size distribution (PSD) of LCM blends. Width estimation of near-wellbore fractures has predominantly been based on assuming axial fracture development from wellbores. However, this assumption is not valid for all wellbore orientations. Shallow vertical and highly inclined or horizontal well sections in a normal subsurface faulting regime may give rise to configurations where drill-induced fractures develop transverse to the wellbore axis. A transverse fracture yields a substantially different width compared to an axial fracture. This study aims to demonstrate the width contrast between the two fracture geometries and the impact that such contrast would have on the LCM blend design. For this purpose, the width of near-wellbore transverse fractures is estimated using a linear elastic fracture mechanics solution to an axisymmetric model of the same. Contrary to the case of hydraulic fractures, the solution must consider the effect of wellbore cavity boundary conditions on the fracture width profile. Two case studies involving horizontal and vertical boreholes are examined. Results indicate that the assumption of axial fracture geometry could lead to substantial underestimation or overestimation of the fracture width depending on the wellbore inclination and magnitudes of the in-situ stress components. Application of the solution in selecting the compositions of blends made from three LCMs is demonstrated. The discrepancy between the LCM blends PSDs obtained based on the axial and transverse models of the wellbore fracture are discussed.

Application of Remote Wireless Intelligent Layered Water Injection Technology in Dagang Oilfield

A remote wireless intelligent layered water injection technolo-gy is proposed to address the problems of traditional layered water in-jection well testing in oil fields, such as the inability to achieve continu-ous dynamic monitoring of injection parameters, high failure rate, and low success rate of testing and commissioning. The technology consists of a host computer client, a server, a surface controller, and an under-ground intelligent water distributor. The underground intelligent water distributor takes the injected water as the carrier, and uses the fluctua-tion of the water injection pressure in the tubing for signal transmission to realize two-way communication between the ground controller and the downhole intelligent water distributor. The underground intelligent water distributor integrates high-precision pressure gauges, controllable water nozzles, and calculation and control modules to form an intelli-gent control system, realizing the reception of ground down transmitted commands or data, the calculation and control of water injection flow rate of water nozzles, and the storage and upload of underground data. Remote wireless intelligent layered water injection technology has been applied in 43 wells, with a success rate of 100%. The maximum depth is 3897m, and the maximum wellbore inclination is 56.07°. This tech-nology realizes remote control of water injection wells, intelligent au-tomatic measurement and adjustment, real-time data monitoring, and automatic early warning functions, laying a foundation for the con-struction of “Digital Intelligence” oilfield.

A Survey on the Shortcomings of the Current Rate of Penetration Predictive Models in Petroleum Engineering

In drilling engineering, the rate of penetration (ROP) is a prevalent indicator to evaluate the energy efficiency of drilling operations. Nowadays, ROP prediction has become more critical since the production from deeper hydrocarbon resources is unprecedentedly escalating. So far, a wealth of theoretical and practical investigations has been conducted to develop ROP models; however, the existing models have not been adequately updated with the new technological advancements or geological restrictions. This research strives to integrate the latest advancements, restrictions, and future requirements in ROP prediction. To do this, the existing empirical and data-driven ROP models are elaborated and compared. From the conducted research, it was deduced that four uncontrollable factors, including the rock permeability, wellbore inclination, temperature, and rock hardness, have not been adequately considered in ROP models. Moreover, although data-driven ROP models deliver more accurate results than the empirical models, the determination of the number and type of the input parameters is still challenging. To tackle this issue, it is recommended to develop a formation-based classification system of input parameters for future investigations. This inclusive review can be adopted by the companies and engineers involved in drilling operations to update and reform their drilling strategies.

Study on the Influence Law of Temperature Profile of Vertical Wells in Gas Reservoirs

Due to the lack of a robust temperature model and poor knowledge about the influence law of temperature profile, it is still highly challenging to interpret the production profile of vertical wells in layered gas reservoirs from distributed temperature sensing (DTS) quantitatively. In this paper, a coupled temperature prediction model for vertical wells in the layered gas reservoir is developed, considering several microthermal effects and non-isothermal seepage. Based on the theoretical simulation, several single factors' influence on the vertical well's temperature profile in a layered gas reservoir has been analyzed. The sensitivity of temperature profiles on different affecting factors has been evaluated through orthogonal test analysis. It has been found that the influence degree of each factor on the temperature profile of the vertical well in the layered gas reservoir is as follows: formation permeability > production rate >water saturation > wellbore inclination angle > relative density of natural gas > formation thermal conductivity > wellbore diameter (k >Qg > SW > θ > dg > Kt > D). The dominant factors affecting the temperature profile of vertical wells in layered gas reservoirs are formation permeability, production rate, and water saturation. The proposed temperature prediction model can serve as the forward model when developing the inversion system to interpret DTS measurement. The findings of this paper provide solid theoretical support for the quantitative interpretation of the flow rate profile for vertical wells in layered gas reservoirs.

Effect of Fluid Viscosity and Fiber Length on the Performance of Fibrous Fluid in Horizontal Well Cleanout

SummaryDuring drilling, completion, and intervention operations, solids can deposit in the wellbore. Innovative cleanout fluids reduce the problems associated with inadequate hole cleaning. Various methods have been developed to improve hole cleaning, but their effectiveness decreases as the wellbore inclination increases. One way to solve this issue is to add fibers to the drilling fluid and reduce the settling velocity of the solids to improve the fluid’s lifting capacity.The purpose of this study is to evaluate the cleanout performance of fibrous fluids in horizontal wells using a large-scale flow loop. Thus, flow loop experiments were conducted to assess the impact of fiber on equilibrium bed height. The experiment measures equilibrium bed height and pressure loss in an eccentric annular test section. During the investigation, the flow rate and apparent viscosity of the fluid and fiber length were varied.The results demonstrate the effectiveness of long fiber (length = 0.5 in.) in improving hole cleanout in horizontal wellbores. When a small amount (0.04% wt.) of long fiber was added, the cleanout performance of the high-viscosity fluid did not show a noticeable change. In contrast, the performance of the low-viscosity fluid improved. Even though adding fiber has minimal impact on the apparent viscosity of the fluids, the long fiber improved the cleaning performance of the low-viscosity fluid.Hole cleaning is challenging in operations such as coiled tubing (CT) in which rotating the drillstring is impossible. Hence, this study focuses on cleanout operations in horizontal wellbores without drillstring rotation. The novelty of this work lies in demonstrating how the adjustment of fluid viscosity can positively impact the hole cleaning performance of fibrous fluids in the absence of pipe rotation. The study also presents a new approach to modeling the effects of solids bed irregularity on wellbore pressure loss and equivalent circulating density (ECD).

Numerical Simulation of Sulfur Deposition in Wellbore of Sour-Gas Reservoir

Sulfur deposition has an important effect on the productivity of sour-gas wells. Accurately predicting the occurrence of sulfur deposition and the location and amount of sulfur deposition in wellbore can effectively guide the production of gas wells. In this paper, the wellbore sulfur deposition model, pressure model, and transient temperature model are established for various well types. Then, numerical simulations of sulfur deposition in the sour-gas well were conducted by coupling these models. Examples show that the proposed methodology has high accuracy, and the average relative error of the calculated results is 3.61%. Based on the model, a sensitivity analysis was performed on the factors affecting sulfur deposition. The results show that with the increase of wellbore inclination angle, the critical sulfur carrying velocity first increased and then decreased, and the maximum critical velocity is about 30% larger than that of the vertical section. The amount of wellbore sulfur deposition increases with increased production time and decreased wellbore pressure, and the amount of wellbore sulfur deposition decreases with increased gas production rate, H2S content, and inclination angle. The results suggest that the sour-gas reservoir should be developed with the horizontal or deviated well, timely adjust the production system, and keep the gas-well production higher than the critical flow rate as much as possible. At the same time, wellbore heating and insulation, pre-cleaning technology, and the closely implemented sulfur deposition prevention technology in the middle and late stage of development can be adopted to reduce the occurrence of sulfur deposition to ensure the safe and efficient development of high-sulfur gas wells.

Three dimensional wellbore feature of air drilling hole and its influence on bit side force

In existing drill string mechanics analysis, smooth and regular wellbore is assumed and makes the calculated results sometimes differ greatly from the actual situation. In this study, based on measured data, the well characteristics of air drilling are shown from static and dynamic aspects, which proves the irrationality of this assumption. A six-arm calliper logging tool was applied to measure the wellbore data, and a cubic spline function was firstly adopted to reconstruct the wellbore. Then a 3D dynamic visualization description of the wellbore was realized based on the visualization toolkit. The results indicate that the 3D dynamic wellbore view can intuitively describe the characteristics of a high ovality and notable axial irregularity of the cross section of the wellbore drilled with BHA with an air hammer (AH-BHA), while the wellbore drilled with a pre-bent pendulum bottom hole assembly(PBP-BHA) exhibits low ovality and a smooth and regular shape along the axial direction. This can explain why it is difficult to run casing in a hole section drilled with AH-BHA. The FEM calculation example shows that the regularity of wellbore has a great influence on the bit side force. The BHA, which generates a bit side force that would reduce wellbore deviation in regular wellbore, may even produce a bit side force that increases wellbore inclination in severely irregular wellbore, and can be used to reveal the deviation mechanism in the air/gas drilling process. Importantly, this result indicates that the assumption of irregular wellbore should sometimes be taken seriously in drill string mechanical analysis.

Integrated Mechanical Earth Modeling for Predicting Sand Production: A Case Study

Summary Sand production is a serious problem in oil and gas wells, and one of the main concerns of production engineers. This problem can damage downhole equipment and surface production facilities. This study presents a sand production case and quantifies sanding risks for an oil field in Iraq. The study applies an integrated workflow of constructing 1D Mechanical Earth Modeling (MEM) and predicting the sand production with multiple criteria such as shear failure during drilling, B index, and critical bottomhole pressure (CBHP) or critical drawdown pressure (CDDP). Wireline log data were used to estimate the mechanical properties of the formations in the field. The predicted sand production propensity was validated based on the sand production history in the field. The interpretation results of some wells anticipated in this study showed that when a shear failure occurs during drilling, the B index is around 2 × 104 MPa or less and the CBHP is equal to the formation pore pressure. For this case, sand control shall be carried out in the initial stage of production. On the other hand, when the shear failure does not exist, the B index is always greater than 2 × 104 MPa, and the CBHP is mostly less than the formation pore pressure. In this case, implementing sand control methods could be postponed as the reservoir pressure undergoes depletion. However, for the anticipated field, sand control is recommended to be carried out in the initial stage of well production even when the CBHP is less than the formation pore pressure since sanding will be inevitable when the reservoir pressure depletes to values close to the initial reservoir pressure. The tentative evaluation of the stress regime showed that a normal fault could be the stress regime for the formations. For a normal fault stress regime, the study explained that when the reservoir permeability is isotropic, an openhole vertical wellbore has less propensity for sand production than a horizontal wellbore. Moreover, when the wellbore azimuth is in the direction of the minimum horizontal stress, the CBHP will be lower than in any other azimuth, and sanding will take place at higher wellbore inclination angles. For the anticipated field, because of the casedhole well completion and the anisotropic reservoir permeability, a horizontal well drilled in the direction of minimum horizontal stress with oriented perforation in the direction of maximum horizontal stress is an alternative method for controlling sand production.

Experimental Study of Cuttings Transport with Non-Newtonian Fluid in an Inclined Well Using Visualization and Electrical Resistance Tomography Techniques

Summary Hole cleaning is a concern in directional and horizontal well drilling operations where drill cuttings tend to settle in the lower annulus section. Laboratory-scale experiments were performed with different non-Newtonian fluids in a 6.16-m-long, 114.3- × 63.5-mm transparent annulus test section to investigate cuttings transport behavior. This experimental study focused on understanding the cuttings transport mechanism in the annulus section with high-speed imaging technology. The movement of cuttings in the inclined annular section was captured with a high-speed camera at 2,000 frames/sec. Also, cuttings bed movement patterns at different fluid velocities and inner pipe rotations were captured with a digital single-lens reflex video camera. The electrical resistance tomography (ERT) system was used to quantify the cuttings volume fraction in the annulus. Different solid bed heights and cuttings movements were observed based on fluid rheology, fluid velocity, and inner pipe rotation. The mechanistic three-layer cuttings transport model was visualized with the experimental procedure. This study showed that solid bed height is significantly reduced with an increase in the inner pipe rotation. This study also identified that cuttings bed thickness largely depends on fluid rheology and wellbore inclination. The image from the high-speed camera identified a downward trend of some rolling particles in the annulus caused by gravitational force at a low mud velocity. Visual observation from a high-speed camera identified a helical motion of solid particles when the drillpipe is in contact with solid particles and rotating at a higher rev/min. Different cuttings movement patterns such as: rolling, sliding, suspension, helical movement, and downward movement were identified from the visualization of a high-speed camera.

Hydraulic Behavior in Cased and Open-Hole Sections in Highly Deviated Wellbores

Abstract In this paper, we present results from flow loop experiments with an oil-based drilling fluid with micronized barite as weight materials. The use of micronized barite allows using lower viscosity drilling fluid, providing non-laminar flow, which is advantageous for particle transport in near-horizontal sections. While transition to turbulence and turbulent flow of non-Newtonian fluids has been well studied both theoretically and experimentally, there are very few published results on the effect of wellbore wall properties on flow regime transition and turbulence. This is relevant because horizontal sections are often open hole with less well-defined surfaces than a steel casing surface. We have conducted a series of flow experiments with and without cuttings size particles in a 10-m long annular test section using steel and concrete material to represent the wellbore wall of a cased and open-hole section. In both cases, the annulus was formed by a freely rotating steel pipe of 2” outer diameter inside a 4” diameter wellbore. Experiments were conducted at 48 deg, 60 deg, and 90 deg wellbore inclination from vertical. The two materials result in different hydraulic behaviors without particles with stronger turbulence when using concrete wellbore wall material than when using steel casing. While there is a negligible difference at low flowrates, at 0.8 m/s and below, there is an increasing difference as the flowrate increases and becomes transitional to turbulence. Hole cleaning is found to differ dependent on the wall material. However, the effect on hole cleaning is less clear than for the pressure loss.

The Effect of Inclination on the Stability of Foam Systems in Drilling and Well Operations

SummaryTo minimize fluid loss and the associated formation damage, foam is a preferred fluid to perform cleanout operations and reestablish communication with an open completion interval. Because of their high viscosity and structure, foams are suitable cleanout fluids when underbalanced well-cleanout operations are applied. Although several studies have been conducted to better understand foam-flow behavior and hydraulics, investigations performed on foam stability are very limited. Specifically, very little is known regarding the impact of wellbore inclination on the stability of foams. Unstable foams do not possess high viscosity, and as a result, they are not effective in cleanout operations, especially in inclined wellbores. Predicting the downhole instability of foam could reduce the number of drilling problems associated with excessive liquid drainage, such as temporary overbalance, formation damage, and wellbore instability. The objectives of this study are to investigate the effects of wellbore inclination on the stability of various types of foams and develop a method to account for the effect of inclination on foam stability in inclined wells.In this study, foam-drainage experiments were performed using a flow loop that consists of a foam-drainage-measurement section and pipe viscometers. To verify proper foam generation, foam viscosity was measured using pipe viscometers and compared with previous measurements. Drainage experiments were performed with aqueous, polymer-based, and oil-based foams in concentric annulus and pipe under pressurized conditions. Tests were also conducted in vertical and inclined orientations to examine the effect of wellbore inclination on the stability of foams. The foam-bubble structure was examined and monitored in real time using a microscopic camera to study bubble coarsening. The foam quality (i.e., gas volume fraction) was varied from 40 to 80%.Results show that the drainage rates in the pipe and annular section were approximately the same, indicating a minor effect of column geometry. More importantly, the drainage rate of foam in an inclined configuration was significantly higher than that observed in a vertical orientation. The inclination exacerbated foam drainage and instability substantially. The mechanisms of foam drainage are different in an inclined configuration. In inclined wellbores, drainage occurs not only axially but also laterally. As a result, the drained liquid quickly reaches a wellbore wall before reaching the bottom of foam column. Then, a layer of liquid forms on the low side of the wellbore. The liquid layer flows downward because of gravity and reaches the bottom of the test section without facing the major hydraulic resistance of the foam network. This phenomenon aggravates the drainage process considerably.Although foam-drainage experiments have been reported in the literature, there exists only limited information on the effects of geometry and inclination on foam drainage and stability. The information provided in this paper will help to account for the effect of inclination on foam stability and subsequently improve the performance of oilfield operations involving foam as the working fluid.

Simulating fracture initiation from inclined wellbore in layered reservoir using analytical model

ABSTRACT For the layered reservoirs such as shale, the anisotropic mechanical properties exhibit variations in elastic modulus and tensile strength, both of which are factors influencing fracture initiation pressure (FIP) from the wellbore. The previous works are mainly concentrated on analyzing the influence of elastic modulus anisotropy but the anisotropic tensile strength is usually ignored. In this study, we extended the previous work by considering the effect of both elastic modulus and tensile strength anisotropy to predict FIP in layered reservoir. The analytical solution of stress concentration around wellbore in anisotropic reservoir is adopted, and a layered tensile strength formula applied to 3-D stress conditions is developed. We verified the model with numerical simulation and experimental data. Results show that both elastic modulus anisotropy and tensile strength anisotropy are important factors affecting FIP, and the influence of anisotropic modulus is greater than anisotropic tensile strength. FIP reduces monotonously with the degree of Young’s modulus anisotropy and tensile strength anisotropy increasing. Besides, when the Young’s modulus anisotropy ratio (the ratio between the Young’s modulus in the layered planes and normal to the layered planes) is larger than 3, there is a drastic reduction of FIP by 100% at high wellbore inclination (≥75°). Furthermore, the effect layered planes occurrence is tremendous when the wellbore is close to parallel to the layered planes, and the reduction of FIP can be as much as 17%. Moreover, the influence of anisotropy on FIP is significant under normal fault and strike slip, and the maximum FIP reduction is 19%. This work is meaningful for developing unconventional reservoir.

A Semiempirical Model for Rate of Penetration with Application to an Offshore Gas Field

SummaryIn this paper, we present an accurate semiempirical rate of penetration (ROP) predictive model for polycrystalline diamond compact (PDC) bits. Our model is inspired by the model of Bourgoyne and Young (B&Y) and follows an exponential form with 10 different drilling functions to account for various factors affecting ROP in drilling operations. We extend the B&Y model to the PDC bits and discuss that a different predictive model should be obtained for each formation. On top of the factors included in the original B&Y model, our model accounts for parameters such as downhole motor, equivalent circulating density, mechanical weight on bit (WOB), and wellbore inclination. In particular, we incorporate the effect of equilibrium cuttings bed thickness and downhole cuttings concentration in the ROP model. The parameters of the model are obtained using multiple regression analysis with the field data. The importance of obtaining a formation-based ROP model is tested and verified with field data, and an algorithm to determine the parameters for new data is provided. The model can be incorporated in a framework to obtain an optimal well plan for a new well or for prescribing optimal operational parameters for well planning and real-time drilling operations. The prediction performance of the proposed model is also evaluated in various formations for several test wells across an offshore gas field. Our results indicate that the proposed model is able to predict the drilling ROP with an accuracy of more than 90%.