Extended Reach Horizontal Wells Research Articles

Numerical investigation of flow patterns in cuttings transport for extended-reach horizontal wells with rotation drillpipe

During the drilling process of extended-reach horizontal wells, the formation of the cuttings bed at the bottom of the wellbore is prone to cause drilling sticking and pump accidents. A coupled method of Computational Fluid Dynamics and Discrete Element Method (CFD-DEM) is used here to study the flow patterns and transition of cuttings transport. Firstly, the model is validated with experimental results, which shows a good agreement. Then, the impact of the rotation speed, eccentricity, and conveying velocity on cuttings flow pattern are analyze. The total Reynolds number is introduced here to established a curve with dimensionless pressure drop, which divides the parameter interval of each flow pattern, and the change rule of cuttings flow pattern is also revealed. This study will establish a theoretical foundation for enhancing borehole cleaning efficiency and hold practical significance in guiding the drilling field construction of extended-reach wells.

Study on the Mechanical Extended-Reach Limit Prediction Model of Horizontal Drilling with Dual-Channel Drillpipes

Extended-reach horizontal wells are critical for the development of unconventional reservoirs. Dual-channel drill pipe drilling has a great advantage in improving the horizontal section length, while the research on its mechanical extended-reach limit prediction model is insufficient. In this paper, the torque and drag model is built considering the additional axial force of the sliding piston on the dual-channel drillpipe. Based on the torque and drag model, the mechanical extended-reach limit model for dual-channel drilling is established. A case study including a comparison to the conventional drilling method and sensitivity analysis is conducted. The result shows that under the same conditions, the mechanical extended-reach limit of the dual-channel drilling method is 10,592.2 m, while it is 9030.6 m of the conventional drilling method. The dual-channel drilling method achieves a further mechanical extended-reach limit than the conventional drilling method. To improve the mechanical extended-reach limit of dual-channel drilling, a higher back pressure on the sliding piston, a deeper measured depth of the sliding piston, a higher density of the passive drilling fluid, a smaller outer diameter of the outer pipe, a lower weight on bit and rate of penetration should be adopted. The work in this paper completes the extended-reach limit theory of dual-channel drilling, providing a guide for better use in unconventional reservoir development.

Downhole electric heating of heavy-oil wells

Downhole electric heating has historically been unreliable or limited to short, often vertical, well sections. Technology improvements over the past several years now allow for reliable, long length, relatively high-powered, downhole electric heating suitable for extended-reach horizontal wells. The application of this downhole electric heating technology in a horizontal cold-producing heavy oil well in Alberta, Canada is presented in this paper.
 The field case demonstrates the benefits and efficacy of applying downhole electric heating, especially if it is applied early in the production life of the well. Early production data showed 4X-6X higher oil rates from the heated well than from a cold-producing benchmark well in the same reservoir. In fact, after a few weeks of operation, it was no longer possible to operate the benchmark well in pure cold-production mode as it watered out, whereas the heated well has been producing for twenty (20) months without any increase in water rate. The energy ratio, defined as the heating value of the incremental produced oil to the injected heat, is over 20.0, resulting in a carbon-dioxide footprint of less than 40 kgCO2/bbl, which is lower than the greenhouse gas intensity of the average crude oil consumed in the US.
 A numerical simulation model that includes reactions that account for the foamy nature of the produced oil and the downhole injection of heat, has been developed and calibrated against field data. The model can be used to prescribe the range of optimal reservoir and fluid properties to select the most promising targets (fields, wells) for downhole electric heating as a production optimization method. The same model can also be used during the execution of the project to explore optimal operating conditions and operating procedures.
 Downhole electric heating in long horizontal wells is now a commercially available technology that can be reliably applied as a production optimization recovery scheme in heavy oil reservoirs. Understanding the optimum reservoir conditions where the application of downhole electric heating maximizes economic benefits will assist in identifying areas of opportunity to meaningfully increase reserves and production in heavy oil reservoirs around the world.

Development of Hybridized Completions for Extended Reach Horizontal Wells

Non-uniform production and injection profiles in extended reach horizontal wells invite several production and recovery issues. Downhole flow control devices, along with dynamic reservoir modeling, have been beneficial in regulating flow, improving productivity from the toe section, delaying water breakthrough, reducing water coning, and improving overall reservoir sweep. However, such measures add to substantial completion costs and may not be economical for marginal reservoirs. Using simple slotted liners is a cheaper option but may not be effective in regulating injection/production profiles in the longer term. This research focused on applying “coupled static and dynamic modeling” to examine and compare five different types of completion designs, using data from a heterogeneous carbonate reservoir. Results show that inflow control device (ICD) integrated completions can achieve better recovery than the slotted, pre-perforated, or engineered liners. Engineered-slotted liners perform better than the pre-perforated-slotted liners. The pre-perforated-slotted liners do not show much improvement over open-hole completions. Finally, a hybrid completion design is optimized by combining ICD with engineered-slotted liners, which showed higher well productivity, lower water cut production, and reduced completion cost.

A New Predicting Method of Build-up Rate of Steering Tools Based on Kriging Surrogate Model

Build-up rate is a key technical parameter of the steering tools in the drilling of complex directional wells, especially sidetracked wells, lateral wells and extended-reach horizontal wells. However, prediction of build-up rate is affected by various factors and very difficult to use explicit quantitative formula to portray its accuracy. So it is necessary to seek a scientific and efficient prediction method to be directly applied in drilling those wells, to improve wellbore trajectory control accuracy and speed, reduce development costs and improve economic efficiency. Based on hot methods of drilling engineering, from a regression analysis point of view, a novel method is proposed, which uses the Kriging surrogate model to build the predictive performance function to predict the build-up rate. In order to verify the effectiveness and superiority of the method, based on one field drilling data, Kriging surrogate model and commonly used regression models which are first-order polynomial regression models and radial basis function model, are built. Their three common performance indicators, i.e., root-mean-square error, maximum absolute error and average absolute error, are calculated and compared. The results reveal that, under different types of testing samples, the prediction performance of Kriging surrogate model is superior to the other two models in the three selected indicators. As to the computational process and prediction performance, the proposed method has better prediction performance, more robust prediction results, low computational complexity and more efficiency.

Acid Jetting in Carbonate Rocks: An Experimental Study

Summary Acid jetting, as a well-stimulation method for carbonate reservoirs, has shown optimistic results in the production enhancement of some extended-reach horizontal wells. It was used initially to promote damage removal along a wellbore by means of multiple strategically located injection nozzles. It has the potential to place the injecting fluid at the locations that need stimulation. Jetting may also enhance wormhole propagation compared with conventional matrix acidizing. The hypotheses for the design of more-efficient stimulation treatments are currently being investigated. We have conducted an experimental study to investigate the effect of jetting on wormhole efficiency. Each jetting experiment was conducted as a constant-pressure (equivalent to a desired initial flux through the core) linear coreflood test, in which a standoff distance is maintained between the injection nozzle tip and the core. At low-velocity acid injection, jetting effectively removes mud filter cake by mechanical actions. Jetting also creates wormholes in limestone cores. The combination of mechanical and chemical reaction stimulates limestone rocks better than matrix acidizing without the jetting nozzle. When the jetting velocity increased, the dissolution pattern changed. An isolated local compact dissolution results in a cavity at the entries of core samples by jetting, followed by a wormhole structure. With the known dissolution pattern, sensitivity studies are carried out to investigate the effect of various parameters on the experimental outcome. We used Indiana and Winterset limestone rocks in the experiments. A 15% hydrochloric acid (HCl) (by weight) at ambient temperature was used, and the core dimensions were 4 in. in diameter and 16 in. in length. Various combinations of acid jetting velocities and acid fluxes were considered. The Winterset limestone cores are more heterogeneous, with higher porosity and lower permeability than the Indiana limestone cores. The experimental results from the two different rock samples are compared. Overall, the experimental results indicate that acid jetting follows the same trend as matrix acidizing, regarding wormhole propagation after cavities are created. Jetting velocity and acid flux are the critical parameters in jetting design for optimal stimulation results. Acid jetting tends to create different dissolution patterns for the cores from Indiana limestone and Winterset limestone. The observations from this work highlight the importance of understanding the dynamic physical and chemical process of jetting in the design of successful acid-stimulation jobs.

Modeling of Filter Cake Composition in Maximum Reservoir Contact and Extended Reach Horizontal Wells in Sandstone Reservoirs

Drilling mud should be properly designed to build an effective filter cake on the formation face during the drilling process. This filter cake should be removable to allow the oil and gas production. The need for removal increases when the liftoff pressure is high or when the formation drawdown is extremely low. An effective filter cake removal design includes the knowledge of the filter cake composition along the horizontal section. This paper, for the first time, introduces material balance model to predict the composition of the filter cake along the length of the lateral of an actual horizontal well drilled in a sandstone formation. The model is based on the material balance of two sources of solids: the first one is the drilling fluid solids and the second one is the drilled-formation solids. The mud used to drill the rock was contaminated by the drilled-formation solids. The parameters used to construct the model were composition of the mud and formation, efficiency of each separation stage, rate of penetration (ROP), and mud circulation rate. The model was validated with actual mud samples collected from different locations along the horizontal section of a sandstone formation. The model showed that the sand content in the filter cake is affected by ROP, rock composition, mud composition and volume, and efficiency of sand separation equipment. We came up with several correlations that can be used to design the drilling fluid operations in horizontal well to avoid the formation of irremovable filter cake.

Surface Torque/Tension Measurements Used To Detect and Calculate Stick/Slip

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 170624, “Stick/Slip Detection and Friction-Factor Testing Using Surface- Based Torque and Tension Measurements,” by Stephen W. Lai, SPE, Mitch Wood, Aaron Eddy, SPE, and Trevor Holt, Pason Systems, and Matthew Bloom, SPE, Nexen, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed. A surface-based torque and tension sub (TTS) was used to perform measurements while drilling several extended-reach horizontal wells. A filtered version of surface torque was used to calculate a stick/slip metric, which was compared with stick/slip measurements from a downhole tool. The results show that there is reasonable correlation between surface and downhole metrics. A comparison was also made between hookload measured with a deadline sensor and tension measurement from the surface sub. The results show a systematic discrepancy of approximately 5% that is likely caused by sheave friction. Torque- and Tension-Measurement Tool A commercially available TTS was used to perform accurate measurements of surface torque and tension for this study. The TTS measures torque and tension at 50 Hz and transmits the readings to the surface system by a wireless link. The surface electronic-drilling-recorder (EDR) system is used to display the readings to the driller and to store the raw 50-Hz data for post-processing. The TTS is shown in Fig. 1. The main body consists of a stainless-steel core on which several strain-gauge sensors are mounted. Measurements of mechanical strain in tangential and axial directions are used to calculate the magnitude of rotational torque and axial force being applied to the sub. A circular housing surrounds the middle of the core and contains the sub electronics including sampling circuits, radio transceivers, and replaceable batteries. Data are transmitted with two omnidirectional antennas that are directed downward toward the doghouse. A remote antenna radio module is placed in the doghouse or near the rig floor to receive the transmitted data. The TTS is powered by two disposable lithium batteries, which have an operational life of 40 days per battery. In this study, the TTS was installed in the topdrive assembly directly below the mudsaver valve (Fig. 1).

Drilling Fluid Technology for Extended-Reach Horizontal Wells in Cuba

This Extended-reach horizontal wells lies in Guanabo block of Cuba, using the KCl polymer drilling fluid system which has strong inhibition. To strengthen the drilling fluid inhibition, it keeps the concentration of GW FA-367 at around 0.5% in the construction, KCl is 8%~10%, GW POLYCOL is 2% ~ 3%, it also takes the use of other assorted maintenance treatment measures at the same time. The results of application show that, compared with other wells of this region, this well greatly shortens the drilling cycle, reduces the accident rate and the drilling cost, the drilling fluid lubricity is good.

Coiled-Tubing and Jointed-Tubing Hybrid String - A New Approach to Well Intervention

Young Technology Showcase As oil reserves mature around the world, oil companies look to improve the recovery of existing assets and to tap into unconventional reserves such as shale gas and tight gas. Coiled tubing (CT) and jointed tubing (JT) have progressed to larger sizes and premium material grades to adapt to these new and extended applications. However, some situations, such as long horizontal or ultradeep wells, remain where either the CT or JT is unable to provide the required reach efficiently and safely. Combining CT and JT can bring the flexibility of CT to extended-reach horizontal wells. Typical well intervention operations present several challenges, including equipment and reel availability, transportation issues, achievable flow rates, and the ability to reach the target depth of the well. CT is prone to sinusoidal buckling and eventual lockup in deviated and horizontal wells. This means that friction-reducing agents or mechanical aids such as tractors may be necessary to reach target depths. Smaller CT reduces the flow rate that can be achieved and requires higher horsepower to overcome fluid friction. JT, on the other hand, is larger and heavier than CT but requires constant making and breaking of connections during trip in and trip out, which requires redundant safety measures and reduces the effectiveness of downhole operations. In shale plays, operators have determined that laterals in excess of 10,000 ft and more than 30 fracturing stages are necessary to maximize production and achieve the desired return on investment. These wells are challenging to complete using only CT. PowerReach Service Boots & Coots, a Halliburton service, developed PowerReach, which combines CT and JT to form a hybrid string that offers the best of both. The resulting string allows for greater depth for long horizontals, high flow rates when using larger CT, and a smaller equipment footprint. The PowerReach system consists of JT at the bottom and CT on top to have the stiffness and weight of the JT at the bottom of the string and the freedom to move the CT portion on top without making connections. The length of CT depends on the length of the lateral or the distance from the first to the last section being treated. This ensures that the string can be moved freely without making a connection. Fig. 1 shows the setup of a hybrid unit on location, including a reel trailer, rig assist unit, and tower with tubing guide.

Technology Focus: Horizontal and Complex Trajectory Wells (November 2011)

Technology Focus Geometrically complex and horizontal wells are constructed to deliver additional production with fewer environmental effects. The continuous success with which we are able to drill, complete, operate, and maintain wells having demanding profiles positioned for stronger reservoir performance is the result of service companies, drilling companies, operators, and technical institutions developing ever-more-advanced and -reliable technology. As new technologies are put to work, new techniques are developed to reduce operational risk, increase payback, and improve efficiency, thereby pushing the boundaries of what previously was considered technically improbable to achieve or uneconomical. As a result, higher-value wells are constructed. Development of these new technologies and techniques continues, but none of this is possible without technically competent experienced people. Well-construction activity has ramped up over the past 2 years. This activity ramp is occurring simultaneously in established areas and “frontier” locations that are remote from upstream infrastructure or are lacking local expertise. As a result, it is challenging to ensure that complex wells gain the focus of the most-experienced technical personnel to deliver acceptable performance consistently. While remote operating centers alleviate some of this challenge, the need for technical training and competency development probably has never been greater than it is today. However, the opportunities to achieve this have never been greater. Every well we construct and operate presents on-the-job-training and competency-development opportunities. We should make greater efforts in identifying these opportunities and in committing to exploiting them. This should be more widely recognized at the planning phase by documenting training opportunities as key well objectives. Achieving these objectives would enhance the value delivered from each well. It is only by focusing on development of people, existing and new to our industry, that the boundaries of horizontal and complex wells will continue to expand, adding production with fewer environmental effects. This must persist irrespective of the business cycle because while there are efficient methods of attaining technical proficiency by commitment to well-structured programs, there are no shortcuts. Horizontal and Complex Trajectory Wells additional reading available at OnePetro: www.onepetro.org . SPE 140332 • “Understanding and Managing Bottomhole Circulating Temperature Behavior in Horizontal High-Temperature Wells—A Case Study Based on Haynesville Horizontal Wells” by Keith Trichel, SPE, Baker Hughes, et al. (See JPT, April 2011, page 87.) SPE 135670 • “Increasing the Reach and Selectivity of Completions in Extended-Reach Horizontal Wells” by Barry Ritchie, SPE, Maersk Oil Qatar, et al. SPE 141089 • “China Offshore Anticollision Risk-Management Standard and Remedial Measures” by Kun Cheng, SPE, Texas A&M University, et al. SPE 146651 • “Texas Panhandle Granite Wash Formation: Horizontal-Development Solutions” by Brian Rothkopf, SPE, Forest Oil Corporation, et al.

Lateral Buckling—The Key to Lockup

Summary Conventional wisdom suggests that buckled pipe first forms a plane buckled configuration, then transitions to a helical shape as the axial load increases. The helical configuration has been studied extensively using analytic solutions that allow calculation and analysis. Lateral buckling has received much less attention because no analytic solution exists for smooth pipe. Most conclusions about lateral buckling are just guesses. Tool joints have received some analysis, and buckling calculations, both lateral and helical, have been made for pipe with connectors, but these calculations have received little attention from the industry. Buckling tests (Weltzin et al. 2009) were performed in the Ullrigg U2, a 2020-m research well with a buildup and 60° tangent geometry. These tests represent a major advance in the understanding of drillstring buckling. Although there have been many laboratory-scale studies and a few full-scale tests of limited value, this study is the first full-scale study to acquire a large amount of high-quality buckling-displacement data for analysis. This paper presents the calculated drillstring positions for two loading tests performed in build and inclined sections of the Ullrigg U2 test well. Both tests were loaded until drillstring lockup. By lockup, we mean that no increase in load could be transmitted to the load sensor at the bottom of the drillstring with further decreases in hookload at the surface. In both cases, lateral buckling was the primary buckling mode, with only a short interval in the build-section tests showing actual helical buckling. The results from the Ullrigg U2 tests show that connectors appeared to have primary importance in the buckling behavior of drillpipe, and lateral buckling was the primary mode of behavior. These results, which were not expected, will require considerable revision of the conventional buckling models with much more focus on the impact of connectors and a deeper understanding of lateral buckling. In particular, the analysis of casing running in extended-reach horizontal wells will be impacted significantly.

A Study of High-baric Gas Cushion Drilling Technology

During drilling of extended-reach horizontal wells, horizontal drill strings touch the low side borehole due to their gravity, so the friction between drill strings and the side wall is high and weight on bit is provided difficultly, which leads to a low rate of penetration. Considering this, a high-baric nitrogen cushion drilling technology is preliminarily studied, the fundamentals and the construction procedures of a high-baric nitrogen cushion rig are given, and two kinds of special drill pipes are designed. Theoretical analysis indicates that this study can help to reduce the friction and effectively apply weight on the bit, which helps to enhance the rate of penetration.

Steam flooding after steam soak in heavy oil reservoirs through extended-reach horizontal wells

This paper presents a new development scheme of simultaneous injection and production in a single horizontal well drilled for developing small block reservoirs or offshore reservoirs. It is possible to set special packers within the long completion horizontal interval to establish an injection zone and a production zone. This method can also be used in steam flooding after steam soak through a horizontal well. Simulation results showed that it was desirable to start steam flooding after six steam soaking cycles and at this time the oil/steam ratio was 0.25 and oil recovery efficiency was 23.48%. Steam flooding performance was affected by separation interval and steam injection rate. Reservoir numerical simulation indicated that maximum oil recovery would be achieved at a separation section of 40–50 m at steam injection rate of 100–180 t/d; and the larger the steam injection rate, the greater the water cut and pressure difference between injection zone and production zone. A steam injection rate of 120 t/d was suitable for steam flooding under practical injection-production conditions. All the results could be useful for the guidance of steam flooding projects.

A Novel Technique To Acidize Horizontal Extended-Reach Wells

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 90385, "A Novel Technique To Acidize Horizontal Wells With Extended Reach," by H.A. Nasr-El-Din, SPE, and N.S. Al-Habib, SPE, Saudi Aramco, and M. Jemmali, SPE, A. Lahmadi, SPE, and M. Samuel, SPE, Schlumberger, prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September. Extended-reach horizontal wells are drilled to maximize reservoir drainage and minimize water production from coning. A problem with these wells is poor acid distribution during matrix acidizing. The full-length paper discusses a new technique that uses mechanical diversion in the wellbore and chemical diversion in the carbonate formation. A hydraulic tractor was used to pull coiled tubing (CT) to the total depth of the well, and a viscoelastic surfactant-based acid system was used to remove formation damage created by drilling fluids. Introduction It is common practice to drill horizontal and multilateral wells to maximize oil recovery in carbonate and sandstone reservoirs. Extended-reach wells are defined as those with a measured-depth (MD) to true-vertical-depth (TVD) ratio greater than 2. Most oil and gas reservoirs are heterogeneous, with significant variations in reservoir permeability. Significant variations in rock permeability in wells with long target zones will cause poor fluid distribution during any chemical treatment. In matrix acidizing treatments, poor fluid placement will adversely affect the outcome of the treatment. Mechanical and chemical means that can enhance fluid placement are available. Mechanical means, including CT, are used to distribute the fluid across the target zone. Chemical means enhance fluid distribution inside the formation. Several chemical diverters have been used in matrix acid treatments including foam and gelled and in-situ gelled acids. Several authors have raised concerns regarding use of polymer-based fluids in tight formations, especially in sour environments. To overcome some of the problems encountered with polymer-based fluids, viscoelastic surfactant-based acid systems have been used successfully in matrix stimulation. Positive field results were reported when viscoelastic surfactant-based acids were used to stimulate oil producers, water injectors, and water-disposal wells.

SEISMIC BASED RESERVOIR CHARACTERISATION OF THE WANDOO OIL FIELD

The Wandoo Oil Field of Western Australia's offshore Carnarvon Basin is located in the WA-14-L production licence approximately 70 km northwest of Dampier. Hydrocarbons from the 22 m thick oil column are produced from the informally named Unit A and Unit B of the Vf. australis Sandstone reservoir through 15 extended-reach horizontal wells. Cumulative production from the field is over 30 MMBBL of the estimated 160 MMBBL initial oil- in-place. Production reached a plateau rate of 40,000 BOPD in April 1997 and is now declining in line with the predicted reservoir performance.A multidisciplinary team was formed to develop a detailed reservoir model using 3D seismic data, a regional 2D seismic database and geological and engineering data from 11 vertical and 19 horizontal wells. The M. australis Sandstone was divided into six depositional units defined by changes in well log character, glauconite content and reservoir quality. These units were subdivided into 27 correlatable flow units and 6 laterally extensive non- reservoir siderite layers.An estuarine-deltaic depositional system is suggested for the M. australis Sandstone reservoir at Wandoo. The recognition of erosional features at various scales and distinct areas of higher quality reservoir indicate that this system wras subject to frequent changes in relative sea level. The top of the Unit B was identified as the most significant sequence boundary with the overlying Unit A deposited as a transgressive sand of limited distribution.A 3D geological model honouring the revised interpretation has been constructed and used as input for reservoir simulation resulting in an improved production history match. The concepts developed have been successfully tested by a horizontal multi-lateral production well.

Drilling Extended Reach Horizontal Wells in the Gulf of Mexico

Drilling Extended Reach Horizontal Wells in the Gulf of Mexico