Friday, November 2, 2018

Coiled Tubing Takes Center Stage

When it comes to coiled tubing, there can be few doubters left. What was once a fringe service has moved to center stage in the oilfield theater of operations. 

For many years, coiled tubing (CT) operations occupied the twilight zone of a fringe service offering niche solutions to specialized problems. However, over the past five years, technological developments, improved service reliability, gradually increasing tubing diameter and an ever growing need to drive down industry costs have combined to dramatically expand the uses of coiled tubing.

Today for example, coiled tubing drills slimhole wells, deploys reeled completions, logs high-angle boreholes and delivers sophisticated treatment fluid downhole. This article will look at the technical challenges presented by these services and discuss how they have been overcome in the field. 

 Drilling Slimhole Wells

Slimhole wells - generally those with a final diameter of 5 inches or less - have the potential to deliver cost-effective solutions to many financial and environmental problems, cutting the amount of consumables needed to complete a well and producing less waste. Other benefits depend on what kind of rig drills the well. Compared to conventional rigs, purpose-designed smaller rotary rigs can deliver slimhole wells using fewer people on a much smaller drillsite, which cuts the cost of site preparation and significantly reduces the environmental impact of onshore drilling.

Coiled tubing drilling combines the virtues of a small rig with some unique operational advantages, including the capability to run the slim coiled tubing drillstring through existing completions to drill new sections below. There is also the opportunity to harness a coiled tubing unit's built-in well control equipment to improve safety when drilling potential high-pressure gas zones. This allows safe underbalanced drilling- when the well may flow during drilling.

Although there were attempts at CT drilling in the mid-1970s, technological advances were needed to make it viable. These include the development of larger diameter, high-strength, reliable tubing, and the introduction of smaller diameter positive displacement downhole motors, orienting tools, surveying systems and fixed cutter bits. Furthermore, currently available coiled tubing engineering software enables important parameters to be predicted, such as lock up -when tubing buckling halts drilling progress- available weight on bit, expected pump pressure, wellbore hydraulics and wellbore cleaning capability.


Through-tubing reentry in underbalanced conditions is a category of CT drilling that may grow significantly. Reentering wells without pulling the production string is a cost-effective way of sidetracking or deepening existing well.

The development of through-tubing, reentry underbalanced drilling is of great interest in the Prudhoe Bay field on the North Slope of Alaska, USA, where operator ARCO Alaska Inc. has an alliance with Dowell to develop coiled tubing technology. The alliance has already scored a number of technical and commercial successes. For example, a 600-ft horizontal section extended using underbalanced CT drilling, resulted in production three times greater than predicted rates.

As with any mature operation, there is a need to extend field life and gain incremental reserves at a cost that reflects today's oil price. While the primary aim is to devise a strategy for for low-cost well redevelopment, a secondary aim is to improve the productivity of horizontal wells by reducing formation damage associated with conventional overbalanced drilling.

In line with these objectives, candidate wells for CT drilling are divided into two classes: 
  • the replacement of waterflood wellbores that have corroded because of the high carbon dioxide content of the water.
  • horizontal sidetracks to replace conventional gravity drain wells, tapping new zones and improving recovery. 
Four years ago, ARCO began sidetracking the existing wells using conventional Artctic rigs. The corroded tubing was pulled and new well sections drilled. ARCO realized that this was going to be a necessary procedure for the future, but that conventional tecnology was going to incur considerable cost. Using a traditional Arctic rig to enter a Prudhoe Bay well, drill the sidetrack and  run a completion costs over $1 million -as many as 800 sidetracks may be needed in ARCO Prodhoe Bay unit.

The goal of the Arco-Dowell alliance is to develop a lower cost alternative to conventional rig sidetracks. To date, promising results show that CT sidetracks can ultimately be performed at half the cost of rig operations. 

The second objective of improving productivity employs underbalanced drilling drilling in new, low permeability zones. Underbalanced drilling offers the opportunity to minimize formation damage incurred during drilling and to optimize the productivity of the completion. As the first case study shows, the technique does seem to offer some benefits.

Underbalanced drilling sometimes helpps alleviate other problems like differential sticking. Oil production during drilling helps the string slide better and aids hole cleaning by carrying cuttings to surface more effectively. 

Drilling and directional control equipment for through-tubing CT drilling is largely proven, although systems require continued refinement and improvement. As higher build rates are achieved, slimmer CT directional tools may be necessary to accomodate through-tubing operations in some existing wells. 

Bit selection must match the geology, motor spesifications and the maximum allowable pumping pressure, while at the same time offer viable rates of penetration with less weight on bit and  higher rotation speeds than is normal. Polycrystalline diamond compact (PDC) bits are commonly used in medium-to-soft formations, and thermally stable diamond or natural diamond bits for harder formations.

A positive displacement mud motor is used to rotate the bit. Most CT drilling is performed using motors with a diameter less than 3 1/2 in, such as Anadrill's 2 7/8-inch steerable motor.

For directional control, dowell uses an orienting tool operated by mud-pump flow rate to alter the tool face. Anadrill's SLIM 1 MWD system coupled with a gamma ray log is used to monitor the wellbore's progress through the formation in real time. Data are transmitted to surface using conventional mud-pulse technique.

There are systems available that use wireline inside the coiled tubing. These can transmit directional data to surface at a higher rate than mud-pulse tools and hold the potential to provide electrical power to activate downhole tools. However, installation and maintenance of the cable increase drilling costs.

In case the bottomhole assembly gets stuck, a hydraulic or shear release tool allows the coiled tubing string to be disconnected and recovered in one piece. A flapper valve just above the disconnection point prevents any wellbore pressure from entering the CT string.

It would, however, be wrong to say that all the mechanical challenges of drilling have been met. For example, transmitting sufficient weight to the bit can be problematic. Since it is impossible to rotate the CT from surface, it is often difficult to overcome axial friction along the length of the CT, particulary in deviated wells. Because of this, the weight applied at surface frequently becomes "stacked up" against the borehole wall instead of reaching the bit. This phenomenon is well known for slide drilling, but is exacerbated by the flexibility of the CT and increases with the sidetrack angle.

Numerous solutions have been proposed, including hydraulically activated "crawlers" that grip the borehole wall and pull the CT into the hole, and hydraulic thrusters that apply weight by pushing on a slip joint or piston just above the bit. 

A conventional kick-off technique uses a whipstock plug- a log, inverted steel wedge that is set in the wellbore and diverts the drillstring toward the side of the hole to initiate a sidetrack. To achieve this through tubing on Prudhoe Bay wells requires a whipstock that will pass through 3 3/4 inch minimum restriction inside the tubing but sit firmly and reliably inside the casing below that has an inside diameter of more than 6 inch, so far this has proved difficult to achieve. 

Development of CT drilling is not exclusive to Alaska. For example, in the North Sea, the Danish Underground Consortium is turning to the technique as an alternative to its pioneering strategy based on long, conventionally drilled horizontal sections completed so that many individual zones may be separately fractured. Because these stimulation treatments and all the associated hardware can be expensive, operator Maersk Olie og Gas believes that a network of slimhole wells drilled quickly and underbalanced with coiled tubing may be more cost-effective. 

To evaluate this development strategy, Dowell and Anadrill drilled the first successful CT drilling offshore development well in the North Sea. The well was completed in May 1994 on Maersk's Gorm platform and initially produced some 3000 BOPD - up to four times the anticipated level. 

To date, CT drilling has not been used as a major exploration drilling tool. One factor that limits its usefulness for exploration drilling is the maximum openhole diameter possible. This is increasing as larger diameter coiled tubing becomes available. With 2 3/8-inch tubing, a vertical open hole of up to 8 1/2 inch may be drilled. Because it is stiffer and can extend farther before lock up, larger diameter CT also allows longer horizontal sections to be drilled. However, horizontal drilling necessitates more trips into the well and more cycling of the CT over the gooseneck.








Thursday, November 1, 2018

Inversion for Reservoir Characterization

Fundamental to reservoir characterization is assigning physical property values everywhere within the reservoir volume. The challenge of using all available data to choose the best assignment is being addressed by a group of scientist. Available data could include seismic data, log data, well test results, knowledge of the of the statistical distributions of the sizes and orientations of sedimentary bodies, and even spesific information about reservoir geometry. 

To incorporate all these diverse sources of information, the scientists use an inversion method that begins by considering all possible assignments. Each assignment is represented by a single point in a multidimensional space that has as many dimensions as there are cells in the reservoir model. In assigning acoustic impedance in a reservoir model comprising 10 x 10 x 10 discrete cell, for example, each assignment would be represented by a unique point in a 1000 dimensional space. 

 The available data are then used to determine which of these points are acceptable. This is achieved by representing each available data set -3D surface seismic data, well data, or whatever -by a cloud of points corresponding to assignments that fit that particular data set. Finding an acceptable assignment then reduces to finding a point that lies at the intersection of all such clouds of points.

As the solution is always nonunique ( more than one assignment satifies all the available information), this intersection set will not be a single point but have some volume in the multidimensional space. A procedure to choose a single, best assignment is therefore required. The current method starts with an initial guess and then modifies it as little as possible until the intersection set is reached.

A synthetic example illustrates the method. First, a reservoir model is constructed 21 x 21 horizontal cells and 201 vertical cells, with an acoustic impedance value assigned to each cell. This synthetic model is equivalent to a volume of about 1 km x 1 km horizontally and 100 milliseconds. From this are generated two data sets that would be measured if the reservoir were real: first, a log of acoustic impedance in a well through the center of the model; second, the surface seismic response, which displays a lower spatial resolution than the original model. 

The challenge is to reconstruct the original acoustic impedance model using the log and seismic data only. A reasonable starting model can be obtained from a simple extrapolation of the well log data. This clearly fails to reproduce structural variations away from the well that appear in the original model. However, modifications to this first guess using in addition the surface seismic data produces a reconstruction that is much closer.