TECHNOLOGY Amoco opens drilling test facility to industry

April 7, 1997
R.V. Westermark OGCI Management Tulsa R.P. Bray Amoco Production Co. Tulsa Rig No. 1 is the main test rig at Amoco's Catoosa, Okla., drilling test facility (Fig. 1). A flow loop is used to research hydraulic behavior of single-phase fluids, hole cleaning, solids settling, and pressure loss (Fig. 2). Twenty-five operating parameters are displayed in real-time at the driller's console (Fig. 3). A full-scale laboratory test rig has been in operation since the late 1970s in Amoco's
R.V. Westermark
OGCI Management
Tulsa

R.P. Bray
Amoco Production Co.
Tulsa

Rig No. 1 is the main test rig at Amoco's Catoosa, Okla., drilling test facility (Fig. 1).
Budget cuts and reductions in expense-related items forced Amoco Exploration Production Technology Group (EPTG) to gradually open its drilling technology test facility (DTTF) to external companies and to collaborations with other technology-interested institutions.

This change not only allowed the DTTF to survive, but it has prospered.

The facilities initially provided a low risk, cost effective environment to advance drilling and completion technology for Amoco by providing a means to rigorously test new downhole tools, fluids, and procedures.

Since the inception of the new objective, the DTTF has more than doubled the work being done for external companies to a point where over half of all testing done at the facilities is for companies other than Amoco. This figure is expected to exceed 60% by the end of 1997.

Test facility

The DTTF has four laboratories, three at a site near the port and town of Catoosa, Okla., and one at the Amoco technology center in Tulsa.

Catoosa facilities include a drilling and completions facility, hydraulics test loop, and coiled tubing test ramp. The drilling simulator lab rig is in Tulsa.

Test Rig No. 1

Rig No. 1 is the main test rig (Fig. 1). It is a single-mast rig, fully equipped with a 330-bbl mud system with solids control equipment, 1,100-hp triplex mud pump, and a top drive for rotating speeds up to 300 rpm. Although a variety of drillstrings can be handled, the facility has two drillstring sizes. One is a light-weight aluminum 41/2-in. drillstring that because of its lower modulus provides torque and vibration characteristics of a longer steel string. The other is a 21/8-in. steel drillstring for smaller holes.

The mud tanks form the derrick substructure. This allows the rig to be on one pad for many tests before a rig move is required. The rig can skid over a seven well pattern.

Additionally, 10-12 test holes are usually drilled through each surface casing by plugging the well back and sidetracking just below surface casing. This minimizes the need to move the rig, drill, and set surface casing for each test.

A Skytop Brewster 1,100-hp triplex is the main mud pump. It can pump 130-700 gpm at surface pressures up to 5,000 psi. The solids control system has two low profile, ultra-fine screen shakers, a set of 12 hydrocyclones, and a Sharples PM 20000 centrifuge. Solids control and mud preparation are handled by the rig crew. The site has a well equipped mud lab, and mud technicians are available.

The hoisting system was fabricated from a Hydra-Rig snubbing unit and can pull 120,000 lb. A Bowen 3.5 power swivel installed in a track serves as a top drive to rotate the drillstring up to 300 rpm.

The system can develop 8,000 ft-lb of torque for drilling. The top of the swivel is designed to allow wire line operations through the swivel. The pipe handling equipment can pull singles and stand the drillstring in a pipe rack that is separate from the rig mast and is less labor intensive than a conventional rig.

Test Rig No. 2

Rig No. 2 is a small, trailer-mounted rig, primarily used for horizontal applications and rotary steerable technology. It is equipped with a Gardner Denver triplex capable of pumping 150 gpm and developing 1,100 psi.

The rig is rated to 2,000 ft and 40,000 lb. A drillstring typically consists of 27/8-in., S-135 drill pipe, and 31/8-in. drill collars.

Contract rigs

Contract rigs are often brought to the Catoosa facility to accommodate a client's specific test requirements on an existing well. Portable data acquisition systems are available for the tests.

Currently, 27 wells at Catoosa are available for contract rigs. Most are cased but 5 have open hole sections.

Hydraulics test loop

A flow loop (Fig. 2) [23940 bytes] is used to research hydraulic behavior of single-phase fluids, hole cleaning, solids settling, and pressure loss. The loop consists of a series of joined pipes (390 ft) with valve manifolds, pumps, and instrumentation for controlling flow rate and temperature.

The loop is suitable for running tests on all types of drilling fluids, tests on polymer fluids, water-based and oil-based muds, weighted and unweighted muds, cements, cement spacers, and other fluids.

The loop has the following components:

  • Moyno pump, 520 gpm at 500 psi

  • Mass flow meter, 12,000 lbm/min capacity

  • Valved flow-control manifold

  • Bit sub for shearing fluids, with two 14/32-in., and two 15/32-in. jet nozzles

  • Data acquisition system (PC-based)

  • Pipe loop sections for a concentric annulus, eccentric annulus, two drill pipe, and three tubing

  • Mud storage and mixing tanks.

Test ramp

The flexibility to adapt to particular needs and requirements and the ability to manufacture test equipment is a strength of the Catoosa facility. The recently built variable-angle test ramp is a case in point.

The test ramp was constructed because there was no real "approved" practice of evaluating coiled tubing whipstock systems.

The most recent test evaluated the capability of coiled tubing conveyed through-tubing whipstock systems to mill through 7-in. and 9-5/8-in. eccentrically cemented casing strings.

The ramp can be operated at 60°, 45°, and horizontal. With a 75-ft working length, the ramp can accommodate 40-ft long test samples and still have room for setting and retrieving tools from the sample. A sled is hydraulically controlled to accurately advance the tools in relation to the sample.

A 150-hp triplex pump is used to circulate fluids during testing.

Measured data are collected in the control room by a PC and tailored to the customer's data requirements. Modifications to include high-pressure and temperature tests are possible.

The tests, lasting several weeks, were resounding successes. More tests are planned for 1997.

Personnel

A drilling engineer has overall charge of facility operations, coordination of testing activity, customer requirements, quality assurance, and scheduling with the various companies involved in the testing.

Two full-time Amoco technicians are assigned to the Catoosa facility.

One technician is responsible for all administrative functions at the facility and works as a site foreman/expediter responsible for material acquisition, environmental compliance, and interaction with other service and research groups.

The other technician is responsible for data collection, processing, interpretation, distribution, and archiving.

A contract tool pusher oversees rig operations, plug backs, kickoffs, safety, and maintenance of mechanical systems. His responsibility includes direct rig crew supervision.

A labor contract alliance with Parker Drilling Co. provides the crews. Rig No. 1 has a three-man crew consisting of a driller, floor hand, and derrick hand, while Rig No. 2 has a two-man crew.

The facility also has available a machine shop, welding shop, fabrication facilities, a 9-ton fork lift, and a 22-ton crane.

The site has a full-time welder/machinist during daylight hours, and he is available for call-out if necessary.

A qualified technician maintains the electronic and hydraulic systems. His responsibility includes repairs, parts inventory, upgrading systems, maintaining as-built drawings, and the installation of any special components needed for a test.

Geology

Lithology is one main reason the Catoosa facility is an excellent drilling laboratory and test site. The geological sections include 1,200 ft of Pennsylvanian, 400 ft of Devonian-Mississippi, and 1,300 ft of Cambo-Ordovician. Basement is at about 3,000 ft.

The varied lithology and shallow depths make the site ideal for testing drilling applications, especially drill bits and downhole tools.

The section between surface and 2,000 ft has been cored, extensively logged, and characterized with rock strength, sonic travel time, and resistivity. The shale and sandstone sections above 1,250 ft are particularly good for evaluating polycrystalline diamond (PDC) bits drilling in transitions from soft to hard and back into soft rock.

Several shale stringers offer hole instability problems such as hydration and sloughing and provide a way to study problems with bore hole enlargement, drilling fluid, and cementing.

Data collection

The DTTF's primary value is that quality data on all aspects of a drilling operation can be obtained.

The rig has precision sensors that are monitored by several computers and stored for customer evaluation. Clients are provided floppy disks or compact disks (CDs) formatted to their specifications.

Analog signals of selected channels are plotted in real-time by a high-frequency strip chart recorder and concurrently captured at a high speed (2,000 bits/sec) in a digital format. Single channel real-time, spectral analysis is also available.

Twenty-five operating parameters (measured or calculated) are simultaneously displayed real-time at the driller's console (Fig. 3) [20452 bytes] and in the data acquisition trailer. The primary drilling parameters recorded are:

  • Hook load

  • Rotary speed

  • Rotary torque

  • Hoist position

  • Mud flow rate

  • Pump pressure

  • Drillstring axial accelerations

  • Drillstring torsional accelerations.

Data gathered from these inputs serve to generate and display calculated variables such as weight on bit, bit depth, and rate of penetration and to compensate for the effects of external influences on other variables (such as drillstring length). Additional channels are available for collecting data from sensors connected for special projects and for collecting data in unusual ranges.

Rig simulator

A full-scale laboratory test rig has been in operation since the late 1970s in Amoco's Tulsa technology center (Fig. 4) [18761 bytes].

The mast extends four stories. The first floor (about 8,000 sq ft) is dedicated as the rig area. Tubulars, mud tanks, rock cores, offices, storage space, and other associated equipment can be maintained and serviced on location.

The full-scale drilling rig can accommodate bits up to 105/8-in. diameter. It is computer controlled and can drill shale or limestone core samples with up to 75,000 lb weight on bit, 500 rpm, and 600 gpm at 5,000 psi circulating capacity using drilling fluid or water.

The rig is ideally suited for testing bits, drilling fluids, and near-bit downhole tools. The rig is relatively easy to use and set up. Depending on the type of rock test performed, as many as five tests can be run in a day.

A 5-ft pressure vessel sits underground and is used to contain the 14-in. diameter rock core that serves as the test formation. The core is placed inside a casing sleeve which is tightened and lowered into the vessel. Metal ears on the sleeve meet ears inside the pressure cell to keep the rock from turning as drilling proceeds.

The system is contained by bolting a flange to the top flange of the vessel, along with bearings and seals, to pack off around the drillstring. A cell extension is also available to add 3 ft to the drillstring.

Five major components of the drilling lab simulator are weight on bit, circulating system, rotary system back pressure system, and data acquisition and computer controls.

Weight on bit

The weight on bit (WOB) system is controlled with a large hydraulic ram that also can pick up the drillstring assembly.

It is controlled by a precise servo valve and is capable of 75,000 lb WOB.

Circulating system

The primary mud pump is a 400-hp triplex pump powered by a 600-hp dc motor. In high gear the maximum flow rate available is 380 gpm at 1,500 psi.

The secondary pump is a 850-hp triplex driven by a dc motor and is capable of pumping 190 gpm at 5,000 psi with the existing liner size.

Both pumps combined allow for a maximum pressure of 5,000 psi at about 380 gpm, or a flow rate of about 600 gpm at 1,500 psi.

Rotary system

The drillstring can be rotated in the range of 30-500 rpm.

A standard rotary table drives a square kelly. It is powered by a fixed displacement hydraulic motor that generates a maximum torque of 6,500 ft-lb.

Back pressure

Back pressure simulates hydrostatic head of the drilling fluid in a well bore. The system is composed of a fixed choke and a variable choke to produce the desired pressure.

The fixed choke unit contains carbide sliding plates and a diffuser. The variable choke can adjust the pressure to the preferred value.

Data, controls

The rig operates in either a manual or computer-controlled mode. Critical electronic sensors mounted on the rig measure about 30 associated drilling parameters. A PC is used to monitor, collect, and store the data from the lab test.

Data are sent to a printer, an eight-pen strip chart recorder, a reel-to-reel tape drive for long-term storage, and a spectrum analyzer to investigate vibration frequencies.

The following drilling parameters (recorded or calculated) are displayed in real time:

  • Weight on bit

  • Rotary speed

  • Rotary torque

  • Bit depth

  • Rate of penetration

  • Mud flow rate

  • Pump pressure

  • Pressure vessel accelerations

  • Mud temperature.

Accomplishments

There are many accomplishments and success stories that have been derived from tests at the DTTF. A few recent ones of merit are: A high-speed project that created a valuable spin-off, wire line retrievable coring tools, and high-density polyethylene casing liner.

High speed project

Sometimes research projects provide valuable knowledge not directly related with the objective of the project. In one case, Amoco and a large international service company initiated a joint project to develop a high-speed drilling system to drill interbedded rock while maintaining a good penetration rate.

Many tests were run with high-speed positive displacement motors and turbines to evaluate natural diamond bits, roller-cone bits, and PDC bits. None of these systems provided a performance better than a properly selected roller-cone bit run on a conventional rotating drillstring. In terms of its original objectives the project failed and was subsequently abandoned.

But some interesting facts were discovered about what caused drag bits to fail and how improved bits might be built.

PDC bits were found to be almost always damaged by chipping of the cutters long before the cutters were abrasively worn. Bit vibration was the primary cause of such chipping and bit whirl caused most of the vibration. This led to the development of anti-whirl bits.

Anti-whirl bits have significantly impacted drilling operations in many areas. But perhaps even more important, is that bit manufacturers are more aware of the need to account for the dynamic downhole conditions in designing bits and other tools.

Coring tools

Three test wells were cored at Catoosa to evaluate continuous coring with a conventional rig and drillstring. These tests were conducted with components that could be assembled at minimum cost.

One test included a modified, 77/8-in. anti-whirl PDC core bit that cut a 17/8-in. core. The bit was made from a full-hole 77/8-in. anti-whirl PDC bit. It was run with a Homco wire line core barrel, 5-in. Hevi-Wate drillpipe, and 41/2-in. aluminum drillpipe.

The bit cored from 271 to 1,383 ft and recovered 96% of the core. The recovered core quality was very good.

This coring equipment could easily be run on any conventional rig with standard drillstring components and with a minimum bore of 2 13/16 in.

The bit was rotated at 120 rpm with 5,000-10,000 lb weight on bit, and flow rates of 350-400 gpm. These operating parameters are typical for a conventional rig. The penetration rates were similar to that of a roller-cone bit in the same formations, and bit life was acceptable.

This testing demonstrated the feasibility of wire line coring with a conventional rig.

While standard commercial equipment of this type is not currently available, these tests provided the basis for proposing development of a wire line coring system for conventional rigs.

Casing liner

Catoosa tests included a new method for repairing casing leaks with a continuous, corrosion resistant, high-density polyethylene (HDPE) liner.

Amoco became very interested in this pipeline repair application and has tested it in several wells with 51/2-in. casing. This work was done to prove the insertion technique and the sealing capability of the HDPE once in place.

After several rounds of Catoosa testing, the system is now being installed in wells in New Mexico and Texas.

The system incorporates a viscoelastic casing liner that is reduced in diameter before being run in the hole. Weight is then used to pull it into the well and maintain the downsized diameter. When the weight is released, the liner expands against the casing wall, providing a seamless patch top to bottom.

The system looks very similar to a coiled tubing operation, and the HDPE liner is run in the well at speed up to 50 ft/min.

Confidentiality

One problem that had to be overcome was the confidentiality aspect of research. Initially, Amoco was reluctant to offer the facilities to companies that would not share the data. However, that stipulation has since been dropped.

All information collected can be held in strict confidence so that only the customer is privy to the data. It is purely up to the client on whether or not the information is shared.

Tests can remain totally confidential where no one outside the data acquisition technologist will know the results. If desired, even back-up data can be erased to ensure security.

Any rig can be cordoned off so that no outside visitors will be allowed on or even near the work being done.

The Authors

R.V. Westermark is employed by OGCI Management and serves as the project coordinator at the Amoco Catoosa test facility. His prior experience includes drilling and production director for Phillips Petroleum, drilling engineer for several independents, and production engineer for Unocal. Westermark holds a BS in petroleum engineering from Montana Tech University. He is a registered professional engineer and member of SPE.
R. P. Bray is the technology director of Amoco's drilling technology test facility. Prior to his current position, he was the supervisor of the fluid mechanics group at Amoco's technology center, and has held various drilling engineering positions with Amoco. Bray holds a BS in petroleum engineering from Montana Tech University and an MBA from Oklahoma City University.

BOOK

History of Line Pipe Manufacturing in North America, by J.F. Kiefner and E.B. Clark. Published by American Society of Mechanical Engineers, United Engineering Center, 345 East 47th St., New York, N.Y., 10017. 224 pp., $42 for members, $52.50 for non-members.

This book provides pipeline operators with historical data on line pipe so that they will be able to operate their pipelines, particularly older ones, with greater confidence in pipeline safety and reliability. History of Line Pipe Manufacturing in North America describes processes for manufacturing pipe, lists manufacturers and ways to identify unknown samples of line pipe, and gives API line pipe specifications