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Technology to the rescue, Part 1

Published by
Oilfield Technology,

Oilfield Technology correspondent Gordon Cope, looks at recent and upcoming developments across a broad spectrum of technologies that are driving the industry forward.

Oil and gas companies all around the world face tremendous pressures to produce hydrocarbons efficiently and economically. Labour, material and service costs are rising, while the commodity price for gas in North America remains depressingly stagnant. While many factors are out of an operator’s control, a host of new drilling and completion technologies allow firms to manage drilling costs, reduce time from spud to completion and increase production per acre.


With the ascendency of unconventional shale gas and oil plays (generally known as resource plays), much of the traditional exploration risk has been reduced. But in order to be profitable, each detail of an unconventional play – well density, drilling process, stimulation technique and a host of other parameters – must be carefully planned prior to execution.

Several service companies offer integrated operations (IO) software that allows companies to co-ordinate geophysical, geological and engineering disciplines, including Halliburton’s CYPHER™, Baker Hughes’ JewelSuite and Schlumberger’s Petrel. IO software allows an inter-discipline team to access a master database in which every pertinent nugget of information is available, and added value is universally accessible. A team can use integrated seismic, geological and petrophysical data to initially determine the optimal well spacing patterns, length of well laterals, stimulation patterns and surface processing facilities.

Cost-effectiveness is a major consideration while planning a resource play well. The drilling engineer has to decide, for instance, at what depth to kick-off a lateral; if 10 000 ft and 3.5° dog-leg is chosen, then less footage is drilled overall, but there is a higher possibility of getting stuck. If the engineer chooses to kick-off at 8000 ft and have a 3° dog-leg, there is less risk of sticking and torque and drag, but the well footage is longer. Hundreds of design scenarios can be compared to optimise the best combination in terms of time, risk and cost.

Return on investment (ROI) is also critical. A 4000 ft lateral might increase production seven times over a vertical well, and a 5000 ft lateral might increase production 7.5 times. The engineer can run a score of scenarios to determine if the 7% increase in production is worth enough to recover added costs.

Cost-effectiveness must be balanced with drilling performance. Much of the planning stage focuses on controlling torque, drag and sticking and slipping. Torque is the amount of circumferential force on the bottomhole assembly (BHA). Drag is the amount of axial force as the drill string pushes down into the rock. Excess torque and drag can cause loss of directional control, a tendency for the hole to spiral and an increase in sticking and slipping. Sticking occurs when the bit is over-engaged in the rock and it stops drilling; energy builds up in the string and eventually overcomes the stick, and the bit slips, causing vibration and damage to the BHA. Analytical software can look at the behaviour of the bit during various rates of penetration. Direction software is used to look at the various trajectory forces on the bit as it cuts a curve through a formation.


New rig technologies are playing an important role in reducing drilling time. Many operators are taking innovations that were developed for offshore wells and adapting them to onshore use. The conventional rig with fixed derrick and manual rig floor is rapidly being replaced by automated drilling rigs (ADRs). The derrick has been superseded by a self-erecting hydraulic telescoping mast. The mast itself has a hydraulic top drive built in, and is equipped with a torque wrench and automatic pipe handler. Conventional manual tongs have been upgraded to hydraulic power tongs.

The ADR operator uses digital controls to set up the various functions and operating parameters for each well (such as upper and lower hoist limits and speed), using the rig’s programmable logic controllers (PLCs). The rig functions are controlled by various joy-sticks, including the drawworks joystick that raises, lowers and stops the travelling blocks, and the top-drive joystick that operates the pipe handler rotation. Drilling information can be displayed in real time, and compared to historical performance in order to consistently optimise weight on bit (WOB) and rate of penetration (ROP).

ADRs reduce non-productive time (NPT) dramatically. While conventional rigs may require 20 loads to move from site to site, comparable ADRs can have as little as four, with the self-erecting mast and other components mounted onto trucks, trailers and skids. Some rigs that are designed to drill multiple wells on the same pad use a hydraulic system in the substructure to ‘walk’ the rig at speeds of 15 - 30 ft/hr between wells. These innovations can add 45 - 75 drilling days per year compared to a conventional rig of similar capabilities.

Switching fuels from diesel to natural gas on drill and service rigs has the potential to reduce costs significantly. EQT Corporation has two bi-fuel drilling rigs operating in West Virginia. The newest rig uses onsite natural gas that has been conditioned for direct injection into the generators. The two rigs alone will create savings of US$ 400 000 per year. The company has plans to add several more bi-fuel rigs this year. Apache Corp, a major gas producer, is working with Halliburton and Schlumberger to implement bi-fuel fracturing systems. The team has conducted several successful tests in Oklahoma, and estimates that energy costs for each fracture were reduced from US$ 123 000 to US$ 74 000.


Drilling mud is designed with several important functions in mind; keeping the hole clear of cuttings, cooling the drill bit face and lubricating the drill string/wall interface. But as wells penetrate into ever-deeper formations, temperature and pressure conditions start to break most conventional mud mixes down. M-I Swaco recently launched the RHADIANT drilling fluid system that can remain stable through drilling and logging right up to the 500 °F threshold. According to the company, it is specially formulated to maintain a stable rheological (the flow of matter in a liquid state) profile. The result is an ultra-thin and slick filter cake deposit that does not interfere with logging, casing and cementing operations.

Baker Hughes has devised a water-based drilling fluid system that improves well bore stability and helps operators increase drilling efficiency in extended lateral sections in unconventional shale plays. Tests show that the LATIDRILL system improves wellbore stability by controlling clay hydration, which can lead to sloughing shale and borehole enlargement. Baker Hughes says the system reduces pore pressure transmission, minimising or even eliminating mud losses. Drilling efficiency is improved through the addition of proprietary lubricants that coat metal surfaces, drill cuttings and formation walls to reduce torque and drag, particularly in high-pressure/high-temperature applications. The lubricants also allow for the delivery of greater amounts of hydraulic horsepower to the drill bit and result in faster rates of penetration.

Drilling fluids materials are also getting much more sophisticated. Drillers are experimenting by replacing barite with 5 µm-sized particles of manganese oxide. The manganese oxide weights up the mud, but does not plug up the reservoir, allowing for greater permeability at the reservoir/wellbore interface. Industry participants note that by designing a sophisticated drilling fluid process, the operator can increase production by 20 - 30%.

Part 2 of this article will be available soon.

Adapted by David Bizley

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