9M.G. Davies et al. (eds.), Pumps and Pipes: Proceedings of the Annual Conference, DOI 10.1007/978-1-4419-6012-2_2, © Springer Science+Business Media, LLC 2011

Abstract The oil and gas industry is loosely divided into three segments. The upstream segment finds and recovers crude oil and natural gas; this includes any-thing from seismic exploration to well completions. The midstream segment deals with the transport of those products after recovery to processing, distribution, or storage. The downstream segment refines and distributes oil and gas products to end users. Robotics and automation have made inroads into each of these segments in varying degrees. This chapter will report on the introduction and integration of these technologies into the upstream and midstream businesses.

Keywords Automation • Completion • Downstream • Drilling • Intelligent well systems • Midstream • Oil and gas industry • Telemetry • Upstream

In popular culture, the term “robot” conjures images of often malevolent anthropo-morphic mechanisms from science fiction. The term is actually derived from “robota,” the Czech word for labor, coined in 1921 by the brother of Czech writer Karel Capek to describe the characters of a play entitled “Rossum’s Universal Robots.” The play’s main characters are a disgruntled group of engineered factory workers.

In the industrial world, the term robot is more mundane and has come to describe a variety of devices guided by automatic or autonomous control that perform com-plicated, often repetitive tasks in place of human workers because of risks or site accessibility.

The first industrial robot was called “Unimate” (Fig. 2.1). Invented by George Devol and Joseph Engelberger, the device was used to maneuver die castings and perform auto-body welding on an assembly line at a General Motors plant starting in 1961. Unimate robots are still in use today. From this first successful installation, robots have been deployed for everything from bomb disposal to human surgical procedures [1].

R.K. Mody (*) Completions & Production, Baker Hughes Incorporated, 2929 Allen Parkway, Suite 2100, Houston, TX, 77019-2118, USA e-mail: rustom.mody@bakerhughes.com

Chapter 2Oilfield Automation

Rustom K. Mody and Edward O’Malley

10 R.K. Mody and E. O’Malley

The oil and gas industry is loosely divided into three segments. The upstream segment finds and recovers crude oil and natural gas; this includes anything from seismic exploration to well completions. The midstream segment deals with the transport of those products after recovery to processing, distribution, or storage. The downstream segment refines and distributes oil and gas products to end users.

Robotics and automation have made inroads into each of these segments in vary-ing degrees. The following sections will provide examples, both successful and otherwise, for the upstream and some midstream businesses.

In the upstream segment the goal is rapid return on investment. Participants want to find and produce product in the fastest, safest, most efficient manner. The seg-ment is decidedly risk averse, and the uptake of new technology can take several years. A common saying among developers of upstream oil and gas technology is that “everyone wants to be first to be second”.

Still, drilling is an upstream segment that has benefited considerably from auto-mation. In the earliest days of drilling, percussive cable rigs were used to create wells for mineral/hydrocarbon extraction. The rigs raised and dropped a weighted bit to pulverize rock, and the cuttings were removed via a bailing bucket [2] (Fig. 2.2). These rigs were dangerous, labor intensive, and slow [3].

After the cable rig, the rotary drilling rig was introduced, which allowed torque to be transmitted to the bit via an electrically or hydraulically powered rotary table mechanically coupled to drillpipe (Fig. 2.3).

As drillers gained experience with this new technique, many further improve-ments were devised. Of particular significance was the addition of control and monitoring of the weight of pipe on the drill bit, as this factor has a significant impact on drilling performance. As early as the 1970s, the industry was considering computer control to further improve the drilling process. However, it was not until the very late 1990s that robust, widely accepted systems were implemented [3].

Fig. 2.1 Unimate robot. Courtesy George Devol. Reprinted with permission

Fig. 2.2 Cable drilling rig. Image used under Creative Commons license, http://www.flickr.com/photos/29251351@N02

Fig. 2.3 Rotary table

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Adoption of the rotary drilling rig put new demands on the roughnecks working the rigs (Fig. 2.4). This new technique required repeated “make and break” of the threaded connections that comprise a string of drillpipe. Early roughnecks applied torque to connections by hand with pipe wrenches, and later with hydraulic wrenches (called tongs). Both methods invited hand injuries. Later advancements included the development of the top drive, an automated device carried within the derrick that can make and break connections with little participation from the rig crew. More recently, several companies have been marketing automated pipe handling systems. These systems are designed to pick up sorted segments of drillpipe from a storage rack, maneuver them into position over the borehole, and then apply torque to con-nect them. The advantages are clear. Far fewer people are in harm’s way on the rig floor, and the cycle or trip time over an all-human crew can be reduced [3].

Within the drilling segment, automation has even found its way into the borehole. In the early 1970s, a communication technique was devised that enabled communi-cation of data from the drill bit to the surface through the creation of pressure pulses in the drilling fluid circulated during drilling. Called mud-pulse telemetry , the tech-nology allows measurements of trajectory and bottomhole conditions to be transmit-ted to the surface so that the driller can react and adjust drilling parameters as needed [3]. Today, downhole steering assemblies and instrumentation have become so reliable that drilling trajectories are simply loaded into memory and the drilling assembly holds its trajectory autonomously using classic closed-loop control.

Fig. 2.4 Rig hands and robotic pipe handling system. Reprinted with permission. Copyright National Oilwell Varco 2006

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The mud-pulse telemetry channel can now be used to “ downlink” with the drilling tools to fine-tune the drilling trajectory in real time [3].

An even faster communication link – wired-pipe telemetry – is in the early stages of acceptance in the drilling segment. Rather than relying on fluid pulses for data transmission, wired-pipe telemetry uses an embedded electrical conductor in specially manufactured drillpipe to carry signals to and from downhole tools. The electrical technique is capable of considerably higher data rates, opening the doors to even more advanced and robust closed-loop control [4, 5].

2.1 Completions

A completion is both the process and equipment used to enable a newly drilled well to flow hydrocarbons from the formation to the surface. Traditionally, oil wells are drilled and then cased and cemented, a process in which a string of large-diameter pipe is inserted into the well and cemented in place. To gain access to the oil or gas formations at the target depth, holes are placed in the casing, cement, and rock formation using ballistic charges, fired from perforating guns. Typical completion equipment for such a well includes a packer, a device intended to anchor in and seal off the casing just above the perforations in the casing; and a string of production tubing, which is smaller-diameter pipe connected to the packer. Production of the well then passes through a bore in the packer, through the tubing, and up to the wellhead at the surface.

The earliest parts of the completion to become automated were at the wellhead. A surface valve was flanged to the top of the casing, where production could be started, modulated (“choked”), or halted by hydraulic or electric valves. As well completions moved offshore, the need arose for a valve to be placed in the comple-tion below the surface in order to control the well in the event of loss of the well-head or platform. The first of these subsurface valves were passive devices, essentially rate-dependent check valves that would close if the flow rate through them became too high. Passive valves were effective at preventing blowouts but had shortcomings: They tended to plug with debris and valve settings could not be adjusted as a result of changes in well pressure [6].

To address these shortcomings, the first surface-controlled subsurface safety valve (SCSSV) was introduced in the late 1950s. This valve was controlled from the surface using steel hydraulic control lines, which allowed a user to open or close it in response to well conditions. The valve also had a fail-safe feature, such that any damage to the wellhead or hydraulic controls would result in valve closure. Though the adoption period was almost 10 years, SCSSVs have become standard equipment in many wells, and are one of the earliest examples of an automated system in a completion [6].

During the productive life of a completed well, it is often necessary to re-enter the well to perform remedial work. Called interventions, these well re-entries include a variety of tasks such as opening or closing valves, removing debris, or

14 R.K. Mody and E. O’Malley

even drilling a new wellbore (called a lateral) using a location in the existing wellbore as a departure point. Intervention tools are carried into the well by a variety of means, including threaded pipe, coiled tubing (a continuous spool of small- diameter steel pipe), slickline (a high-strength steel cable), and electric wireline (a high-strength steel cable with one or more embedded conductors) (Fig. 2.5).

The type of conveyance chosen for an intervention is dictated by several factors, including the goals of the intervention, the well location, the type of wellhead, the size, downhole conditions, well orientation, and even equipment availability and costs.

Threaded pipe such as drillpipe might be selected for intervention where high loads are expected. An example would be a casing exit, in which a new section of well is created by milling a hole through existing well casing and cement, thereby creating a passage to undrilled formation. Historically, a casing exit has been a brute-force service. The site of the exit is determined by the placement of a whip-stock (a long anchored ramp placed in the inside diameter, or ID, of the well that guides a downhole mill against the casing). Once the whipstock is in place, a cut-ting mill is lowered into the well and rotated using the drillpipe or a mud motor to perform the cut. More recently, technology advancements such as mud pulse and wired-pipe telemetry are being considered and even field-trialed for drillpipe inter-ventions. These communication schemes offer the possibility of closed-loop con-trol for downhole cutting operations, resulting in better performance and better decision-making.

Small-diameter coiled tubing might be selected for intervention because the intervention objectives do not require large pulling, pushing, or rotating forces, and the well operator does not want to pull the production tubing out of the well. Since it is a continuous piece of pipe, coiled tubing can be rapidly deployed. When con-nected to downhole tools, it can provide some actuation force (pulling or pushing), create temporary seals, perform milling or cutting operations, or even be used for well stimulation treatments such as fracturing and acidizing.

Coiled tubing is deployed using an injector, a hydraulic device comprising a pair of clamps that grip the outside of the tubing and push it into the well. When a well is highly deviated or horizontal, this pushing technique will only work to a point, after which a device called a tractor must be used (Fig. 2.6). Coiled tubing tractors are connected to a string of coiled tubing tools to aid in reaching target

Fig. 2.5 Slickline unit and coiled tubing unit

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depth. A tractor is comprised of hydraulic and mechanical wheel sections which provide the additional force required to pull coiled tubing into the well [7].

Electric wireline is employed when tools that need electrical power are required. Historically, wireline has been used in well logging (where characterization instru-ments are lowered into a just-drilled well to assess formations) or perforating appli-cations, but more recently it has been used to convey intervention tools such as downhole electric cutters and mills. These devices consist of motors and cutting structures and can make precision cuts to pipe downhole, or remove deposits of scale or paraffin. The tools often incorporate additional actuators for positioning and securing the system while performing a cut [8].

Like coiled tubing, wireline deployments occasionally require the use of tractors when the well is highly deviated or horizontal. Wireline tractors are similar to coiled tubing tractors in both design and function, only the methods of power trans-mission vary [7, 8].

All of these intervention techniques have costs, such as the cost of ceasing production or providing service tools or charges associated with the service pro-vider (mobilization, equipment rental, personnel). The magnitude of the charges will vary based on location, market conditions, and equipment availability, but in general, threaded pipe interventions requiring a derrick to deploy are the most expensive, followed in order of decreasing cost by coiled tubing, wireline, and slickline [15].

Motivated by the prospect of saving money on intervention conveyance as well as by a growing interest in robotics during the 1990s, a joint industry group funded the Micro Rig project in collaboration with robotics giant iRobot. Micro Rig is an intelligent, untethered well tractor (Fig. 2.7). The device is battery-powered and can lower itself to and return from a desired target depth in a well without the use of a rig or spool. Though not strong enough to replace threaded-pipe intervention, Micro Rig can be used in place of wireline and some coiled tubing interventions for tasks such as sleeve shifts or gauge retrieval. The device is also small enough to be transported by helicopter, making it attractive for remote locations. Micro Rig has seen numerous field trials, but has yet to see wide adoption as a viable intervention method [9, 10].

Intervention costs drive many advancements in oilfield technology. As oil and gas wells progress into deeper and deeper water, the infrastructure required to

Fig. 2.6 Welltec Well Tractor©. Reprinted with permission. Copyright Welltec A/S 2008

16 R.K. Mody and E. O’Malley

produce and access the wells is moving from the sea surface to the seafloor. Human divers were first used for installation and service of subsea equipment, at great expense and risk. Tethered remotely operated vehicles are now the pre-ferred method of installation, inspection, and adjustment of equipment on the seafloor. These devices offer highly dexterous manipulators as well as high-quality, real-time imagery, and can be deployed from relatively small service vessels (Fig. 2.8).

Intervention in subsea completions remains a difficult and expensive proce-dure. It was primarily these costs that spurred the industry into considering auto-mation within the well itself to extend the time until intervention, or even eliminate the need for it. Called intelligent completions or smart wells, these downhole systems include the usual completion equipment but add valves, chokes, sensors, and actuators that are remotely monitored by both humans and software [11].

By building in the ability to change well performance in response to well conditions, surface conditions, or even equipment failures, operators extend the

Fig. 2.7 MicroRig robotic intervention tool. Courtesy iRobot. Reprinted with permission

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productive life of the well. The first intelligent completion was deployed in the North Sea in 1997 (Fig. 2.9). For the next 7 years, developers and marketers of intelligent well technology focused their efforts on matters of reliability. Accelerated life testing, failure mode analyses, and variety in engineering tools more often seen in aerospace found their way into equipment design and planning and, by 2004, systems were seeing widespread use [11].

Current intelligent well systems employ electrical, hydraulic, or optical umbili-cals to transmit data and instructions to and from the formation and the surface. These umbilicals are clamped to the outside of the completion equipment as it is run into the well, which makes their deployment fairly complex. Future intelligent wells will benefit from more compact or even integrated umbilicals, and possibly even wireless telemetry. Uphole, data from downhole sensors will move from scru-tiny by human experts to predictive algorithms that offer optimization suggestions not just for individual wells, but for entire fields [12, 16].

Further into the future, wells will change depth or architecture in response to changes in data. Qahtani and Dialdin speculate that future wells will automatically abandon depleted zones and re-deploy material into new sections of wells [13]. Many speculate that nanotechnology will be employed in the development of

Fig. 2.8 Panther ROV. Courtesy Saab Seaeye Ltd. Reprinted with permission

Fig. 2.9 Intelligent completion

18 R.K. Mody and E. O’Malley

microscopic devices that can be pumped through geological formations for exploration , evaluation, and performance monitoring (Fig. 2.10) [13, 14].

2.2 Midstream

In midstream oil and gas operations, the infrastructure is often more accessible, and the environments can be less severe. Because of this, automation solutions have made greater inroads.

Starting at the wellhead, many companies offer autonomous data acquisition and transmission systems that read input from well gauges and transmit data remotely for review. These transmissions systems may be part of an entire field network that can allow limited adjustments to be made to the field performance remotely.

Pipelines also benefit from their relative accessibility and comparatively less hostile environments, since it is now possible to deploy tethered or autonomous inspection devices called smart pigs inside pipelines to perform inspections. These devices can measure and record wall thickness and ID profile, and allow operators to make predictions about corrosion or erosion rate, and determine when to perform maintenance. Robotic smart pigs along with analytical software are the fundamental tools of pipeline integrity management (PIM) programs. These PIM programs aim to replace reactive leak repairs and other failures with proactive, predictive mainte-nance that, for example, repairs problems that can lead to leaks before the leaks occur.

The linkage depicted below is a pipeline inspection robot offered by Baker Hughes (Fig. 2.11).

Oil transport and storage equipment such as tankers also make use of robotic devices for inspection. Tethered robots are used both within the holds of oil tanks and on the exterior hulls of the vessels to look for damage or leaks. Offered by several manufacturers, these devices can execute a pre-set inspection path or be guided remotely (Fig. 2.12).

Fig. 2.10 Technology for future wells [13]. Reprinted with permission. Copyright Offshore Technology Conference and Saudi Aramco, 2009

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Fig. 2.11 Pipeline Inspection Robot

Fig. 2.12 InTank inspection robot. Courtesy Berkeley Springs Instruments LLC. Reprinted with permission

20 R.K. Mody and E. O’Malley

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