Extended Reach Drilling Research Articles

Technology Focus: Well Testing (February 2018)

Technology Focus Well testing and surveillance have always been, and continue to be, the foundations of reservoir management. Fundamental data, such as pressure, rate, and temperature, and fluid samples are collected during a well test and used to investigate the subsurface. With advancements in modern technology such as smart wells, distributed pressure/temperature, real-time measurements, and extended-reach drilling, we are facing conditions with increasing complexity and unprecedented amounts of data. In 2017, several key partnership announcements with major information-technology companies were noticed. The oil and gas industry is going through a digital transformation reinforced by data science; terms such as data cloud/lake, machine learning, Internet of Things, high-performance computing, automation, and model management are the new buzzwords. When analytics are applied correctly, they will provide valuable insights, especially in cases such as unconventional reservoirs with significant numbers of wells. In order to make the transformation a success, many of the industry’s leading experts agree that quality as well as quantity of data should be important. Experience teaches us that the subsurface is always more complex than we expect, feedback is not instantaneous, and issues are difficult to mitigate in the reservoir scale. Hence, essential and information-rich data such as exploration/production-well tests, proper fluid samples, and sufficient/periodic surveillance should still be used effectively as indicators to peel off layers of uncertainty in the complex subsurface. Thus, we conclude that reservoir-engineering fundamentals must still be applied and data should still be quality checked, especially when collecting and applying analytics from a massive amount of information. The age-old “garbage in, garbage out” mantra will continue to apply in the upcoming era of data science. The papers selected for this issue cover advances and opportunities in well testing. They also apply reservoir fundamentals as well as sound engineering judgment, using quantity but also quality data sets from conventional and unconventional assets. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 18924 Current State and Future Trends of Wireline-Formation-Testing Downhole Fluid Analysis for Improved Reservoir-Fluid Evaluation by S.R. Ramaswami, Shell International Exploration and Production, et al. SPE 187348 New Variable Compliance Method for Estimating In-Situ Stress and Leakoff From DFIT Data by HanYi Wang, The University of Texas at Austin, et al. SPE 185795 Step-Rate Test as a Way To Understand Well Performance in Fractured Carbonates by A. Shchipanov, IRIS, et al.

Petroleum and Gas Exploration and Production by Extended Reach Drilling (ERD) Wells

Petroleum and Gas Exploration and Production by Extended Reach Drilling (ERD) Wells

Casing Wear Prediction Model Based on Drill String Whirling Motion in Extended-Reach Drilling

Casing wear has become an increasingly urgent research topic alongside advancements in extended-reach drilling (ERD) engineering. The drill string in an ERD operation is likely to undergo whirling motion, which is known to impact casing wear prediction accuracy; there have not yet been long-term studies on the related mechanisms, however. In this study, we develop a new prediction model called circumferential casing wear model (CCWD) based on the energy principle and the geometric properties, which accounts for the effects of drill string whirling motion on casing wear. Besides, composite casing wear models considering with the CCWD and casing wear groove model (CWGD) are also discussed. The results via case study to find that the proposed CCWD model of whirling motion can contribute to the accuracy of casing wear prediction. If the whirling motion is ignored, a large prediction error could occurred when only CWGD model is used. In the sensitivity analysis, the worn casing depth may increase alongside increases in whirling motion angular velocity, rotary table angular velocity, sliding and rolling friction coefficient, outer tool joint radius, and drill string weight. Slight variations in whirling motion angular velocity and rolling friction coefficient can cause substantial casing wear. Thus whirling motion must be strictly controlled during the drilling process to prevent engineering failure. To this effect, the model presented in this paper has both theoretical and practical applications for enhancing the accuracy of casing wear prediction to develop oil and gas reservoirs in ERD.

The Halladale–Speculant fields: the first nearshore gas fields to be developed from mainland Australia

Extended-reach drilling (ERD) is becoming an increasingly common technique used to explore for hydrocarbons and develop fields in areas where simple vertical wells cannot be drilled due to access problems, stakeholder concerns, environmental issues, poor reservoir quality and/or cost. While these types of wells are generally more expensive and technically challenging to drill than vertical wells, they can be very cost-effective, and if a discovery is made, considerably quicker to monetise when future development costs are also taken into consideration, particularly in offshore environments. In 2014–2015, the conventional Exploration and Production division of Origin Energy (now Lattice Energy) drilled three onshore-to-offshore ERD wells and a geological sidetrack in the Otway Basin with horizontal offsets of 1929, 2576, 4239 and 5152 m targeting an undeveloped gas field (Halladale) and exploration prospect (Speculant) located in Victorian state waters near Port Campbell. The three wells (Halladale-2, Speculant-1 and Speculant-2) and sidetrack (Speculant-2ST1) were drilled during a single drilling campaign from the same pad to reduce mobilisation, drilling and development costs. Halladale-2 was designed to develop the Halladale Field, while Speculant-1, -2 and -2ST1 were designed to evaluate the Speculant Prospect. Both Speculant wells and the sidetrack encountered significant gas columns with Speculant-1 and Speculant-2ST1 subsequently completed as producers after being successfully flow tested. A 33 km onshore pipeline was then constructed to transport the gas from Halladale and Speculant back to the Otway Gas Plant (OGP) for processing and sale. The arrival of first gas at the OGP from the Halladale and Speculant gas fields on 26 August 2016 marked a significant milestone for Origin Energy in terms of accelerated project delivery. It also represented the end of a 15-year journey for Halladale from exploration to discovery to development. The drilling campaign also set several records in the process with: (1) Speculant being the first offshore field to be discovered from mainland Australia; (2) Halladale and Speculant being the first offshore fields to produce gas back to mainland Australia from onshore wells; (3) Halladale-2, Speculant-1 and Speculant-2 being the three longest onshore-to-offshore wells drilled to date in Australia (in horizontal departure terms); and (4) Halladale-2 being the longest well (in mMDRT terms) drilled to date in the Otway Basin. Speculant is a good example of how transition zone (TZ) seismic and ERD technology can be used successfully to explore and develop resources in areas previously considered too difficult by using more conventional seismic acquisition and drilling technology.

E&P Notes (January 2018)

E&P Notes Sakhalin-1 Extended-Reach Well Eclipses 15000 m Matt Zborowski, Technology Writer The Sakhalin-1 consortium has drilled a 15000-m horizontal well from the Orlan platform at Chayvo field in the Sea of Okhotsk, topping four previous wells drilled between 2013 and 2015 that reached between 12,450 ft and 13,500 ft. Partner Rosneft described the well as “super complex” with a 14129-m stepout drilled about 5 km offshore. Sakhalin-1 has been a proving ground for extended-reach drilling (ERD) technology since the first well was drilled there more than a decade ago. More recently, development well O-14 in 2015 was drilled to 13500 m, well Z-40 in 2014 reached 13000 m, and in 2013 wells Z-43 and Z-42 extended to 12450 m and 12700 m, respectively. Case Study: Drone Technology Inspection of UK North Sea Facility Stephen Whitfield, Senior Staff Writer Intel and Cyberhawk, a company that uses drones for asset inspection, released a case study in which commercial unmanned aerial vehicle (UAV) technology helped automate an existing oil and gas inspection workflow within a live structure. The study involved the successful inspection of a gas terminal in St. Fergus, Scotland, with the Intel Falcon 8+, a drone designed to provide unobstructed data capture for 3D reconstruction. The Falcon 8+ captured 1,100 images, translating to 12 GB of data, over the span of 2 days. The data could be used for asset maintenance including premaintenance inspection, repair work, resource planning, and maintenance prioritization. ConocoPhillips Brings Another North Slope Development on Production Matt Zborowski, Technology Writer ConocoPhillips’ operated 1H NEWS viscous oil development, or Northeast West Sak, has started production at the Kuparuk River Unit, 40 miles west of Prudhoe Bay on Alaska’s North Slope. The company expects 1H NEWS to flow 8,000 B/D at peak in 2018. The development, which involved a 9.3-acre extension to the existing Kuparuk Drill Site 1H, comprises 19 new wells with several vertical injection wells supporting horizontal multilateral production wells. Drilling began in August 2017. Production started 2 months ahead of schedule, ConocoPhillips said, adding that the project’s estimated cost of $400 million gross is $60 million lower than the company’s initial estimate. Permitting for 1H NEWS was announced in 2014, and funding and development for the project was approved in 2015. Total Boosts LNG Business With Purchase of Engie Assets Matt Zborowski, Technology Writer Total is expanding its global LNG presence by acquiring assets from Engie for up to $2.04 billion. The deal will provide the French supermajor with 2.5 million tonnes per annum (mtpa) of liquefaction capacity, including a 16.6% interest in Louisiana’s Cameron LNG export terminal—where three trains are under construction and two more can be added—as well as a 5% interest in the first train of Egypt’s Idku LNG project. Total will expand its portfolio of LNG purchase-and-sale contracts, adding supply from Algeria, Nigeria, Norway, Russia, Qatar, and the US with outlets between Europe and Asia. The firm also will gain access to 14 mtpa in regasification capacity in Europe and add 10 LNG tankers to its three existing carriers. AIME Releases Report on Council of Excellence Innovation Efforts The American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME) has released a report titled, “In Pursuit of Technological Innovation,” that outlines the goals and initial analysis of the AIME Council of Excellence, established in 2014 by Behrooz Fattahi, the AIME President at the time. The report is available for free download at www. aimehq.org/programs/collab-orative-efforts/council-of-excellence/article-1. The mission of the AIME Council of Excellence is to convene highly regarded technical experts representing the AIME member societies to continuously identify technologies (mature and/or leading edge) that might have innovative application in the industries served by these societies. These member societies include TMS (The Minerals, Metals, and Materials Society), SME (Society for Mining, Metallurgy, and Exploration), AIST (Association for Iron and Steel Technology), and SPE (Society of Petroleum Engineers). The 2003 TMS President, Dan Thoma, and 2007 TMS President, Robert Shull, are the TMS representatives to the Council of Excellence and coauthors of the report.

A Prediction Model of Casing Wear in Extended-Reach Drilling With Buckled Drillstring

Buckled drillstring easily existed in extended-reach drilling (ERD) engineering, causing casing wear more severe. However, the effect of the buckled drillstring on casing wear prediction is going unheeded in long-term studies. To solve the issue, this paper proposes a new model, named as circumferential casing wear depth (CCWD) model, based on the energy principle and the more complicated geometry relationship than that in casing wear groove depth (CWGD) model. Meanwhile, sensitivity analysis of parameters clearly describes the changing trends among them. With the established composite wear models, the change of casing wear depth versus drilling footage under different composite wear cases is also discussed. The results show that the severe casing wear may occur if there is the buckled drillstring; due to the greater contact force and more sophisticated wear shape than those under nonbuckling condition, a shorter drilling footage could make a larger calculation error when only CWGD model is used. In the case study, the method of the inversion of casing wear factor from the drilled well can be used to predict the well whose structure resembles it; the revised coefficient, the maximum risky casing wear depth can be evaluated for each wellbore section to avoid drilling engineering failure. The new model provides a practical method to improve the prediction accuracy of casing wear in ERD. Neglecting the effect of the buckled drillstring will make the prediction underestimated and a great economic loss, which is significant for ERD.

Casing Wear Prediction with Considering Initial Internal Casing Eccentricity

Casing components in drilling engineering possess problematic internal eccentricity due to mismachining and circumferential wear in the prophase. Said eccentricity markedly affects the accuracy of casing wear prediction. In this study, casing wear efficiency theory and a novel geometric description are used to establish a wear prediction model for the initial internal casing eccentricity in extended reach drilling (ERD). Composite casing wear analysis is conducted to explore wear in the same groove and across a series of different grooves; then, residual depth (RD) is used to evaluate wear in terms of risk. The model parameters are subjected to sensitivity analysis, and a case study is conducted to validate the model. The results show that slight eccentricity significantly affects the accuracy of casing wear prediction and that worn casing depth increases as drilling footage increases in a manner strongly dependent on composite wear. The RD percentage of the worn casing wall markedly decreased as initial internal casing eccentricity increased, particularly at the most dangerous angle; at footage of 6000 m, the RD of worn casing wall by drill string A and C combination was minimal. Initial internal casing eccentricity should be properly accounted for in ERD processes to ensure drilling safety.

From shallow horizontal drilling to ERD wells: How scale affects drillability and the management of drilling incidents

The context of drilling operations is quite variable in geometric scale and complexity. Wells range from Extended Reach Drilling (ERD) wells with measured depths greater than 10 km to exceptionally shallow wells no longer than 2 km but only 200–300 m in true vertical depth. With the objective of achieving greater levels of drilling automation, it is important to understand how the well geometrical scale impacts drillability and the management of drilling incidents.The robust control of the drilling process necessitates the correct management of delays in the system. Some sources of delay are directly linked to physical dimensions, while others are the results of the system infrastructure. Time delays due to the travel of information through a medium belong to the first category while delays due to signal filtering or processing and actuator latency belong to the second category. The transient response of the drilling system greatly influences the controllability of the drilling process and both the detection and reaction times for drilling incidents such as over-pulls or pack-offs.This paper proposes a categorization of the various sources of delay in a drilling system. A brief review of similar sources of delay in other industries is presented first, and then the sources of delay are characterized into four classes: the elasticity, inertia, and friction of the physical system, measurement refresh rate and latency, processing latency, and maximum actuator acceleration. Delays within these four classes are quantified for three different scenarios: a 10 km-long ERD well, a shallow horizontal well, and a three-dimensional shale well. Illustrative examples of the four classes of delay are presented within these scenarios. Any drilling automation system faces a varying set of constraints for each application, which should influence both the automation procedures themselves as well as sensing requirements.The paper illustrates how scale influences the necessary constraints in drilling procedures, by comparing the delay within the full range of drilling scenarios. Human operator and rig system reaction time and variable awareness to drilling dysfunctions are the most limiting factors in improving drilling efficiency. The automation of drilling procedures with robustness considerations for scale and latency issues therefore plays an important role in increasing drilling performance.

Simulation Study on Influences of Wellbore Tortuosity on Hole Cleaning in Extended-Reach Drilling

Summary Wellbore tortuosity or spiraling can lead to the trapping of a cuttings bed in a trough of a tortuous hole, thereby leading to poor hole cleaning in extended-reach drilling. The objectives of this study included quantitatively evaluating the influences of wellbore tortuosity on hole cleaning and cuttings-transport behavior in extended-reach drilling. In addition, the study provided a recommendation of effective drilling practices. The study involved performing hole-cleaning-optimization studies for an extended-reach well with a long horizontal section aiming for maximum reservoir contact, by use of a transient cuttings-transport simulator. The planned trajectory of the well was assumed to have a certain degree of wellbore tortuosity in the horizontal section. The pump rate and bottoms-up circulation operation were optimized on the basis of parameter studies and additional transient simulations by considering the effects of penetration rate and variation in cuttings size. Simulation results indicated the formation of a considerably high cuttings bed, particularly in the downdip intervals (updip in mud-flow direction) at an insufficient pump rate; one-third to one-half of the drillpipe diameter could be potentially buried in a cuttings-deposit bed, and this can result in a packed-off hole or stuck pipe. A higher rate of penetration (ROP) can also cause insufficient hole cleaning. In this case, controlled drilling that maintains a reasonably low penetration rate may be effective. Furthermore, borehole breakout may enlarge hole diameter and generate large-sized cuttings. Both of these can have negative impacts on hole cleaning, and, thus, borehole stability and smooth wellbore-trajectory controls should be carefully considered. To clean these holes, frequent bottoms-up circulations were effective at each stand of drilling even if the optimization of other drilling parameters was limited. The findings also revealed that accumulated cuttings in a tortuous wellbore were trapped in the trough of the hole, and that the bed height of locally trapped cuttings in the downdip intervals could be much higher than that indicated by previous studies.

“Vaguely Right or Precisely Wrong?”: Making Probabilistic Cost, Time, and Performance Estimates for Bluefield Appraisal

Summary We conducted a practical case study that aims at estimating the shapes and parameters of probability distributions for key cost, time, and activity performance inputs required by a risk, resource, and value simulator to conduct a stochastic valuation of a new exploration asset. We analyzed a sample of 73 shallow offshore fields in Australia retrieved from a global field-by-field database that includes reserves, production profiles, financials, valuation, breakeven prices, ownership, and other key metrics for global oil and gas fields, discoveries, and exploration licenses. The reviewed facilities concepts include 40 steel platforms, 2 concrete gravity-based developments, 10 projects with extended-reach drilling, 4 floating production, storage, and offloading (FPSO) vessels, and 17 subsea tiebacks. The aggregate capital expenditure (Capex) of projects in the sample during 1965–2015 is USD 99.1 billion (in nominal terms), which is commensurate with the total asset size of the Australian offshore petroleum industry. We estimate probability distributions for all full-cycle parameters required to generate Monte Carlo Capex, operating expenditure (Opex), and production profiles. In particular, these include facility Capex per unit peak, development-phase duration and scheduling rules, drilling expenditures per barrel of oil equivalent (BOE), cost of exploration and appraisal wells, Opex/Capex ratio, abandonment cost ratio, fraction of hydrocarbons produced yearly at plateau, fraction of hydrocarbons remaining at end of plateau, terminal production rate, and fraction predrilled wells. Most of the aforementioned were found to be log-normally distributed. The paper illustrates a practical application of a simple, yet robust, work flow relying on real industry data to assess the value, risks, and uncertainties of an exploration prospect. It can be seamlessly extended to other basins because of a rich coverage of the online field-analogs database.

The Effect of Different Drilling Fluids on Mechanical Friction

A very important aspect in highly inclined wellbores is the mechanical friction. For extended reach drilling (ERD) and through tubing extended reach drilling (TTERD) this can be a limiting factor. Friction caused by the contact between the drill string and the well casing or borehole is dependent on the drilling weight and fluid properties. Drilling fluids play an important role in determining mechanical friction. The use of oil-based drilling fluids with higher lubricity can reduce torque and drag behavior and minimize stick and slip. Reducing mechanical friction will improve drilling efficiency in general, and will in particular enable longer reach for ERD wells. This paper presents results from experimental laboratory tests where the mechanical friction has been investigated. Friction behavior was investigated for different drilling fluids; water-based and oil-based drilling fluids both with and without solid particles. A pin on disk setup was used for these experiments where a spherical ended steel pin was slid against a rotating disk made of granite. The test results show that the mechanical friction in general is smaller with oil-based than water-based drilling fluids in the presence of solid particles.

Technology Update: New Intelligent Completion System Enables Compartment-Level Control in Multilateral Wells

Technology Update Although early inflow control devices and intelligent completions (ICs) were introduced almost 20 years ago, completion technology has not kept pace with advancements in drilling technology. Today, wells completed in multilayered reservoirs, multilaterals with compartments of varying pressure, and extended-reach drilling (ERD) with wellbores as long as 12 km are becoming common. In complex, hard-to-reach reservoirs and tighter formations, operators need to maximize reservoir contact in every well to optimize reservoir drainage and minimize costs. Yet the evolution of ICs has lagged, creating a technology gap with significant ramifications. IC reliability has been steadily increasing over the years, reaching more than 97% for the life of the well in many applications. Most permanent downhole monitoring and control solutions still consist of a separate “kit” of products rather than an integrated system. Traditional IC systems lack sufficient real-time measurements in individual producing zones to facilitate “cause and effect” decision making. Without detailed compartmental information and control in case of water or gas breakthrough, operators are forced to restrict production, intervene, and in some instances work over the entire well. Until recently, there has been no way to maintain production from other unaffected zones during the long diagnostic process of production logging, well testing, interpretation, and execution of an appropriate well intervention. The typical optimization cycle substantially raises operating costs while delaying vital production for weeks or months. Consider Saudi Aramco’s experience with ICs in remote oil fields, where tight formations and a shortage of suitable surface locations drove the need to dramatically increase reservoir contact per wellhead. Before 2007, the company had successfully drilled and completed a number of multilateral ERD wells, achieving more than 5 km (16,400 ft) of reservoir contact per well. These maximum reservoir contact (MRC) wells were completed with then state-of-the-art IC technology. Completions consisted of permanent downhole gauges (PDGs) and downhole flow-control valves (FCVs), which could be partially or fully opened or closed by hydraulic control lines from the surface. Monitoring and control stations were installed in the motherbore above the junction to each side lateral.

General approach for the calculation and optimal control of the extended-reach limit in horizontal drilling based on the mud weight window

There are two shortcomings in the previous open-hole extended-reach limit model: 1) only the drilling process is analysed, while the whole processes should also include the tripping process; 2) the optimal control methods have not been fully considered.To overcome these shortcomings, a set of calculation and optimal control methods of the open-hole extended-reach limit in horizontal drilling are presented in this paper. First, the horizontal section limit expressions of a horizontal extended-reach well (ERW) for different drilling processes are obtained. A modified mud weight window (MWW) for a horizontal ERW is determined according to those expressions, and the modified MWW can be used to solve the problem that the conventional MWW may fail to satisfy the operation window of horizontal extended-reach drilling (ERD). Second, the horizontal section limit values of the drilling process (sliding drilling mode and rotating drilling mode) and the tripping in and tripping out processes are calculated, and the minimum of these values is taken as the maximum horizontal section limit. Finally, several optimal control methods of obtaining the greater horizontal section limit are also provided from three aspects: drilling modes, drilling parameters and mud performance parameters.The results of the case study show that the modified MWW can change with the different operating parameters, rather than remain constant range. Moreover, the modified MWW is narrower than the conventional one. The maximum horizontal section limit should be simultaneously determined by the processes of drilling, tripping in and tripping out. The tripping velocity has little effect on the optimal mud density, whereas the maximum horizontal section limit decreases with the increase in tripping velocity. In addition, both the optimal mud density and the maximum horizontal section limit decrease with the increase in drill string rotation speed. Moreover, the sliding drilling mode can provide greater extension ability than rotating drilling mode. Furthermore, methods of optimizing the drilling parameters and mud performance parameters are also given in detail.

Investigation of Biodiesel-Based Drilling Fluid, Part 2: Formulation Design, Rheological Study, and Laboratory Evaluation

Summary This paper presents an environmentally friendly, biodiesel-based invert-emulsion drilling fluid (BBDF). On the basis of the stable emulsion previously optimized (which was presented in Part 1), several necessary additives, including an organophilic clay (OC), a fluid-loss (FL) -control agent and a rheological modifier (RM), were developed or selected to formulate the BBDF. Numerous laboratory tests of different properties were conducted to evaluate the properties of this drilling fluid. BBDF has a rheological behavior and filtration properties that meet the requirements of drilling operations. It exhibits good shale-inhibition ability, excellent lubricity, and tolerance to contaminants. Low toxicity and great biodegradability are the prominent advantages of this system. After evaluating the suitabilities of known rheological models for BBDF, a hydraulic simulation was carried out on the basis of the Herschel-Bulkley model. BBDF performs similarly to conventional oil-based drilling fluids (OBDFs) subject to deepwater drilling conditions. High performance and great environmental compliance make BBDF a promising option for marine or extended-reach drilling. In addition, novel OC produced from rectorite and nonionic surfactants was successfully introduced into this drilling fluid. This modified rectorite is expected to be a substitute for conventional organobentonite.

New Rotary Shouldered Connection Expands Capability of ERD Operation

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE/IADC 168049, “New Rotary Shouldered Connection Expands the Capability of World-Record ERD Operation,” by S.R. Sanford, SPE, and M.W. Walker, SPE, ExxonMobil; and J.N. Brock, M.J. Jellison, SPE, and A. Muradov, SPE, NOV Grant Prideco, prepared for the 2014 SPE/IADC Drilling Conference and Exhibition, Fort Worth, Texas, USA, 4–6 March. The paper has not been peer reviewed. Eight of the world’s 10 longest wells have been drilled by ExxonMobil as operator of the Sakhalin-1 project in Russia. Components and drilling tools involved in the well design are evaluated and redesigned throughout the program to maximize penetration rate and reduce flat time. Drillstring-torque capacity was recognized as a limiter for increasing penetration rate and for reaching total measured depth capability. The operator consequently sought an alternative drillpipe connection with higher torque capacity. Introduction The Sakhalin-1 project comprises the Chayvo, Odoptu, and Arkutun Dagi fields off the east coast of Sakhalin Island, Russian Federation (Fig. 1). Development drilling at the Chayvo field started in 2003 with extended-reach wells drilled from an onshore location with the Yastreb drilling rig. In 2005, further development drilling commenced from the offshore Orlan platform site. Subsequently, in 2008, the Yastreb rig was moved approximately 75 km north to the Odoptu onshore wellsite and drilled nine extended-reach-drilling (ERD) wells as part of the initial-stage development of Odoptu. During the Odoptu campaign, it was determined that a higher-torque 5?-in. drillpipe connection with good runnability was needed. Following the Odoptu campaign, the Yastreb rig was moved back to the Chayvo onshore wellsite in 2011 for further development and infill drilling of the Chayvo reservoirs. Limiter Identification During the first drilling campaign at Chayvo, available topdrive torque limited drilling performance in the long production hole section (>3000 m). Installation of a new topdrive capable of continuous torque in excess of 90,000 lbf-ft at 140 rev/min eliminated this limiter. During the subsequent Odoptu drilling campaign, the 5?-in. drillpipe connection was identified as a new limiter affecting rate of penetration (ROP) and torque operating margin in the production hole section.

Rotation by Reciprocation Casing-Landing Technology

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 172144, “Rotation by Reciprocation Casing-Landing Technology,” by R. Gosselin and T. Montgomery, Longhorn Casing Tools; A. Muriby, SPE, and Moataz Yussef, Wildcat Oilfield Services; and S. Karrani and A. Khamis, Abu Dhabi Marine Operating Company, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. With the innovation of extended-reach and directional drilling, running casing and liner strings has become increasingly difficult. Not much has been done to address the challenges, which include ledges and obstructions, washouts, swelling shale, bridging, high doglegs, difficult well profiles, fill on bottom, and well collapse. To overcome the challenges, a new product line was developed as a way to facilitate casing operations, especially for long horizontal strings, production strings, and intermediate casing strings. Introduction The technology can rotate independently from the casing when encountering obstructions and hanging. The rotation is performed by reciprocating the casing through 3- to 5-ft strokes that cause the tool shoe to act as a bit and ream. It drills off the obstruction and guides the casing string through ledges, tight swollen sections, and doglegs, allowing effective removal of fill and debris from below the casing/liner shoe to land at the intended total depth (TD). The technology comprises two main components: the tool body, which is made similar to the casing grade being run, and the internal mechanism, which is made from industrial-grade aluminum alloy for the mandrels and bronze components for the bit, both of which lend strength and durability to the tool while facilitating a smooth clean drillout with a standard polycrystalline-diamond-compact (PDC) bit. Technology Concept The tool provides rotation at the end of the casing string by reciprocating the casing string rather than by rotating the string at surface. It uses a very small amount of hydraulic pressure, provided by the mud pump, to enable the removal of fill by penetrating through it and circulating it out. Also, it provides deflection of the casing shoe to bypass ledges. The tool has a fixed helical mandrel connecting to the casing string, so the lower tool body is able to rotate. Only 21 psi of internal hydraulic pressure is needed to extend the lower tool body along the mandrel into an open position. By applying this pressure, the mechanism at the lower assembly of the tool rotates and extends into an open position. By setting weight on the tool, the lower assembly moves up along the mandrel, causing right-hand rotation on the lower assembly by lowering the casing string. The tool is effectively torque neutral, causing no torsional torque transmitted up the casing string.

ICD Well History and Future Use in a Giant Oil Field Offshore Abu Dhabi

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 171836, “ICD Well History and Future Use in Giant Offshore Field, Abu Dhabi,” by Graham Edmonstone, Curtis Kofoed, Alfred Jackson, Shardul Parihar, Adriana Alvarez, Saad Mumtaz, and Ghassan Abdouche, Zakum Development Company, and Chris Shuchart, Christian Mayer, and Andrey Troshko, ExxonMobil, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. As part of a project that involves the use of four artificial islands to drill and complete more than 300 extended-reach-drilling (ERD) wells in a giant offshore oil field, several completion designs have been piloted for brownfield development. One well design incorporated the use of inflow-control devices (ICDs) and swell packers, which was the operator’s first use of such technology in a production well. The technology was installed in the pilot well to test inflow control and to manage future water production. Introduction The giant 1200-km2 offshore oil field is located 84 km northwest off Abu Dhabi Island and consists of a layered carbonate formation that was discovered in 1963. It has still only produced a small percentage of original oil in place, with water cut (WC) less than 15%. There have been almost 500 wells drilled in the field since field discovery. Development was based on pattern producer/injector wells, with each well using a dry tree on a wellhead platform tower. To achieve the strategic goal of increasing the production rate by approximately 40% and maintaining a plateau for up to 25 years, a brownfield development plan (UZ-750) has been generated that will use four artificial islands (Fig. 1) with large 3,000-hp land drilling rigs. The aforementioned island arrangement will allow the drilling of approximately 360 wells that will use ERD to drill horizontal laterals approximately 10,000 ft in length at measured depths up to 35,000 ft. The brownfield development plan calls for a parallel line drive for producer/injector-well pairs, to provide optimum sweep of the reservoir. The well-completion type is determined by geologically defined areas, which are differentiated by High- and low-permeability regions Faulted and fractured regions Transition regions Current (predicted) oil-water-saturation profiles The well-design process takes these into account along with sector modeling to determine well-completion design for the life of the well. Typically, wells in the crest of the field will have an ICD liner, in the near west of the field will have a predrilled liner, and in the west/ far northwest of the field will have a stimulation liner.

Optimization Leads to Successful Deepwater Extended-Reach Drilling Offshore West Africa

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE/IADC 163485, “Offshore West Africa Deepwater Extended-Reach Drilling: Drilling-Optimization Case History,” by Hernando Jerez, SPE, Rafael Dias, SPE, and Jim Tilley, SPE, Halliburton, prepared for the 2013 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 5–7 March. The paper has not been peer reviewed. A deepwater extended-reach well for a major operator in west Africa required a tangent section in a soft formation. The detailed drilling plan included the use of a tailored bottomhole assembly (BHA) with a point-the-bit rotary-steerable system (RSS) and an extended-gauge bit. The BHA had to overcome the tendency of the formation to drop inclination while creating a high-quality wellbore to provide sufficient hole-cleaning capacity in the deeper sections. Introduction West Africa has seen a significant shift in drilling activity, mainly in deep water. Many of the major international operators are carrying out important exploration-and-development activities there. Typical field-development plans in offshore projects call for step-out directional and extended-reach wells, to reach and develop large areas from a single drilling platform. A solid drilling plan is required for success with an extended-reach well. The plan should be comprehensive but feasible for achieving the desired results. In this case study, the extended-reach trajectory called for the delivery of build rates in the 17½-in.-hole interval not previously reached in the shallow soft formations, building up to an 85° sail angle. For the 12¼-in. tangent interval, the BHA must hold the angle and step out the well along a faulted shale and later turn the well more than 60° in azimuth to intersect the reservoir properly. A proprietary, state-of-the-art BHA planning tool was used to model and design the appropriate BHA for each interval. Different iterations were performed to account for potential hole enlargement, build-rate response, vibration mitigation, and hole cleaning. The proposed solution was to use a point-the-bit RSS with attributes to overcome hole enlargement and deliver the planned trajectory and hole quality. The RSS was used to drill all of the directional intervals. All intervals were drilled casing to casing in one run, with one BHA per section. Case Study—Main Drilling Challenges The case-study well is an oil producer, planned to reach approximately 6800-m total depth. The main objective is to drain the reserves located in an unswept area of the reservoir that cannot be reached with conventional well profiles. The plan called for building angle in the surface hole to 85° inclination and keeping the sail angle close to the top of the reservoir, then turning 60° in azimuth and dropping to an inclination of 70°. The critical well challenges included the ability to obtain sufficient and smooth build rates in a soft formation and manage hookload and torque-and-drag loads critical to the successful stepout of the well. Another critical challenge was the narrow mud-weight window, which, on the basis of the calibrated hydraulic model, was required to control rate of penetration (ROP) to keep the equivalent circulating density (ECD) in the safe-operation window.

Dual-Drillpipe Method Shows Success in PMCD Wells With Cuttings Return

Technology Update The Reelwell Drilling Method (RDM) is a new technology developed to solve certain drilling problems and improve the operation margin for various applications. The technology uses a specially designed dual drillpipe (DDP), shown in Fig. 1, that has two flow channels, one for the flow of drilling fluid into the well down to the bit and the other for the return flow of fluid from the bottom of the well back to the surface. Developed in Norway, the RDM has been field tested at various locations in the past several years. The technology has features for pressurized mud cap drilling (PMCD), managed pressure drilling (MPD), and extended reach drilling (ERD). The RDM enables PMCD with cuttings return MPD with a constant well pressure profile ERD with reduced torque and drag, no equivalent circulating density (ECD) in the wellbore, and no cuttings in the hole The DDP is available in 6?-in. steel and 5?-in. to 7½-in. aluminum pipe diameters. With a pressure rating of 5,000 psi, the DDP contains a concentric inner pipe with a stab-in connector and is handled in the same way as a conventional drillpipe. The RDM can be adapted to a standard drilling rig, with the following tools and arrangements: A top drive adapter—a swivel directing the fluid return through a second standpipe and mud hose An inner pipe valve—a bottomhole assembly (BHA) tool for the isolation of the drillstring during connections A flow control unit—a skid with a control valve system for flow and pressure control A rotary control device—a standard tool at the blowout preventer for MPD The RDM uses standard BHA components and drill bits, and the tools operate on reduced flow rates.

New-Generation Drillpipes Enhance Extended-Reach Drilling in South China Sea

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 16798, ’New Generation of Aluminum Drillpipes Enhanced ERD Performances in the Huizhou Field, South China Sea,’ by W. Scaruffi, E. Cristofanelli, S. Yu, and A. Trocchia, Eni China, and C. Molaschi and A. Merlo, Eni, prepared for the 2013 International Petroleum Technology Conference, Beijing, 26-28 March. The paper has not been peer reviewed. Copyright 2013 International Petroleum Technology Conference. Reproduced by permission. This paper presents the results of a performance-improvement effort in extended-reach drilling (ERD) in three campaigns in the Huizhou HZ 25-4 oil field in the South China Sea. The new methodological approach and the deployment of new-generation aluminum drillpipes (ADPs) have resulted in a reduction of drilling risk and increased cost savings. Introduction ERD allows the reduction of the number of drilling sites, including offshore platforms, artificial islands, or other structures, and allows better control of total field-development costs. In addition, ERD technology makes it possible to reach reservoirs located at a considerable distance offshore, reducing the environmental impact of a wellsite. ERD operations are gaining momentum in the industry because they allow reserves exploitation previously considered too expensive when using conventional drilling methods. In addition, ERD techniques increase singlewell production by enlarging the drainage area. Because of their lighter weight when compared with steel drillpipes (SDPs), the use of ADP is a key solution for drilling extended- reach wells for the following reasons: A reduction in operating costs of approximately 10–20% (including savings in rig-capacity upgrade costs, transportation and energy costs, time-hosting costs, and tool-joint/casing-wear costs). An increase in the horizontal deviation of wells of approximately 10–30% (reduced torque-and-drag effect, less pressure drop, higher buckling resistance). Heightened reserves and production growth. A reduction in operative risk. Comparison of ADPs and SDPs Eni E&P first considered ADPs in July 2003, during the proposal and approval of a research-and-development project.