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Candidate Selection for Horizontal
Drilling with Case Studies in Pennsylvania Sandstone
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Based on a workshop sponsored by PTTC's North Midcontinent Region in Chanute, Kansas on September 15, 2005.
Horizontal wells, given the right circumstances, information and planning, can be superior to vertical drilling technically and economically, and in some instances may be the only economic solution. The questions as to whether to drill, where to drill, well geometry and completion design, and drilling equipment must be thoroughly planned and evaluated by an asset team comprised of reservoir, drilling and completion engineers, exploitation geologist, and drilling contractors.
The problem addressed is to find the most economic drilling solution to extract the maximum reserves in exploiting under-developed and mature oil and gas fields. In considering a horizontal well, this becomes a three-dimensional problem rather than one dimensional. To answer the question requires a cross-discipline asset team and as much petrophysical and geological information as is available. This would include production information and tests, logs, cores and as detailed a characterization of the reservoir as possible for input to the reservoir simulator. (See also PTTC's Central Gulf Regional workshop "Cost Effective Horizontal Well Technology", May 12, 2005— www.pttc.org/solutions/sol_2005/545.htm).
Build Rate, Curve Radius, Horizontal Well, Kick Off Point (KOP), Measurement While Drilling (MWD), Reservoir Characterization, Team Approach, Well geometry
Bob Westermark, Grand Directions, LLC
Introduction (with speaker credit
to Dr. Sada Joshi of Joshi Technologies International, Inc.)
Since the first horizontal well was drilled in the U.S. in 1988, based on the
technology used offshore for directional and highly deviated wells, this
technology has become mainstream. Seventeen thousand wells have been drilled in
the U.S. alone. Canadians in particular have embraced horizontal drilling as
they have coiled tubing drilling, having drilled 12,000 horizontal wells to
date, many underbalanced. Internationally, 5,000 horizontal wells have been
drilled. It has been found to be effective in a number of applications,
including:
They have been found to be particularly effective in shallow, low
permeability, naturally fractured, low pressure reservoirs.
There are a number of things to consider in the selection of reservoirs for
horizontal well drilling applications. Historically, the production ratio for
horizontal versus vertical wells is 3.9 for carbonates and 2.8 for clastics. The
cost ratio is tilted somewhat the other way, with horizontal wells in clastics
costing 2.2 times the vertical cost, but 1.8 times for carbonates, due to
cheaper completion costs. While a new onshore horizontal well from the surface
costs 2 to 2.5 times the vertical well, a re-entry of an existing vertical is
only 0.6 to 1.2 times as expensive as the vertical. Horizontal well production
rates have generally been in the range of 2 to 4 times the vertical well rate
and reserves can range from the same to as much as six times that booked with
the vertical well. About one in three horizontal wells are economic failures,
for a 66% success rate. A rule of thumb is that if the projected cost for a
horizontal well is 2.5 to 3 times as great as a vertical well in the same
formation, there is a high risk of economic failure.
The asset team formed for the project must thoroughly understand the key
parameters for planning a successful horizontal well. These parameters include:
Reservoir Considerations
The first phase of the reservoir study is the data gathering. One
must know the target reservoir. The production data of the wells on the lease or
field of interest should be gathered as well as that of the offsets, including
injection volumes, if applicable, and all drill stem tests (DST), initial
production tests and subsequent production tests. Review all logs: drillers
logs, old e-logs, modern open hole logs, and all cased hole logs as well as any
available cores from the operator or core library facilities. Find or
reconstruct all PVT studies to determine fluid properties. With this information
as input, the reservoir simulator can be used to match history and predict
performance of various project parameters. Vertical well bores should be
evaluated for location, integrity of casing and cement and the cost to
rehabilitate and prepare for whipstock compared with the cost to set 5 ½-in.
casing above the pay zone in a new well. Time and money spent on data gathering,
history matching and scenario testing will be well spent as it can prevent money
spent on an uneconomic project or a poorly designed project.
Geological Considerations
A thorough geological study is required to determine where and in
which direction to drill the well. Vertical wells require pre-drill estimates of
oil in place, log evaluations and post-drill estimates to select the perforating
interval. Horizontal wells require that as well, plus input as to where the
hydrocarbons are in the reservoir aerially as well as vertically. The following
issues dramatically impact horizontal well orientation and completion design:
depositional environment, natural fractures, and wellbore stability. Regional
studies of many plays are available from the geological surveys, sometimes
including remote sensing and surface lineament studies, as a starting point for
understanding the deposition history and fracture system. The rock mechanics
must be understood as that will determine the question of wellbore stability and
the completion technique - open hole, slotted liner, or cemented liner or
casing. To plan the path and direction the exploitation geologist must determine
the formation dip and strike, the location of faults from seismic, and the
reservoir continuity. Depending on those factors a well may be planned to be
completely horizontal, tilting upward with the formation or slanted through the
formation, or even snaked up and down within the formation. Part of the well
plan should include the kick off point, well path, coring and logging program
and planned DSTs.
Completion Considerations
The goal of the completion design is to determine a high rate,
low maintenance, trouble-free economical completion. The completion engineer
decides the position of fluid withdrawal based on well geometry, reservoir
fluids, rock properties and flow barriers. They must anticipate the hole
stability and plan for completion type, whether and how the well will be pumped,
and estimated production rates. Tubing size dictates the casing and hole size -
basically the whole well design. Based on the hole stability and anticipated
fluid movement there are a number of options for the completion: open hole,
slotted liner, pre-packed screen, gravel pack, external casing packers for zonal
isolation, or cemented casing. It is also very important to know accurately the
bottom hole pressure. A low pressure makes it very difficult to remediate
formation damage. Finally, the need for stimulation must be carefully planned.
The stimulation of a horizontal well in the Midcontinent can be $500,000, the
same as a vertical well drilled and completed.
Drilling Considerations
The drilling radius for a horizontal well can loosely be defined
as ultra short, short, medium, or long. The important issues are the weight on
the bit and bending the pipe to drill the curve. The ultra short radius is in
the range of 1 - 5 feet. Anything greater than 500 feet is considered to be a
long radius. Those curves are seldom used in the field.
A radius of 40 to 100 feet is considered to be a short radius. It is generally
drilled with a hole size from 3 7/8-inch to 6 ¼-inch with curve drilling
assemblies and articulated mud motors. The lateral length out of the short
radius is limited to 1500 feet due to the inability to overcome friction and put
weight on the bit. With short radius turns it is possible to log while drilling
and open hole logging suites, although there are tool limitations due to bending
concerns. Short radius holes need to be specifically designed and there is a
need to check bending forces with the tubular design. The drill pipe rotation in
the open hole is limited and there are concerns for the pipe due to bending.
A radius of 100 to 500 feet is considered to be a medium radius. It can be
drilled with conventional or articulated mud motors and usually utilizes smart
steerable systems. The horizontal section can extend out as far as 5,000 without
tractors. It also can utilize logging while drilling and open hole logging
suites. A limited amount of rotation in the lateral portion of the hole is
possible and the bending concerns are less with the larger radius. Short radius
curves are used to minimize casing strings, when lease boundaries are an issue,
to minimize geological surprises and for multi-lateral completions. The
advantages of the medium radius curve is better zone isolation, better cementing
possibilities (7-inch hole, versus 4 ½-inch for the short radius), longer
laterals and lower torque requirements.
Logistical considerations include an adequate location size, roads with all
weather access and an allowance for call out of services. Rig considerations
include a crew with horizontal well experience, adequate hoisting capability and
mast height, good mud pumps and cleaning system, required handling tools for all
down-hole tools and tubulars, and appropriate well control equipment. Tubulars
should be high strength N/L-80 or P-105 with shouldered connections and
sufficient inside diameter for logging tools. Bit considerations include solid
body bits, good nozzle design for minimal pressure drop and good cleaning.
Generating drilling fines could lead to formation damage. To minimize formation
damage, the driller should use one mud for the curve and another for the
lateral. The options for the lateral include fresh- or salt water-based
polymers, natural to synthetic oil-based muds and underbalanced with air/foam or
nitrogen/foam.
With a new well, the driller usually drills through the target formation and
runs logs, then cements back to the kick off point, then drills the curve with a
curve drilling assembly. With an existing well, cement is set at least 70 feet
above the target formation, the casing is milled out and then the curve drilled
with the curve drilling assembly. The problems the driller must be prepared to
overcome include lost circulation, sloughing shales, stuck pipe, and tool
parting failure. Possible outcomes include plugging back and sidetracking
horizontal section, plugging back to the kick off point and starting over, or
plugging back above the original kick off point and drilling a larger radius
curve.
Case Studies
Several case studies were presented with successes, failures and
lessons learned. The greatest detail was provided on a Grand Resources, Inc./DOE
co-funded horizontal waterflood pilot project in Osage County, Oklahoma. This
project is in a depleted Bartlesville sand that had not been successfully
waterflooded as it was too difficult to stay below parting pressure and still
inject sufficient volumes using vertical wells. The initial pilot was based on
logs that showed a 30 foot oil column with 52% saturation and good permeability.
The reservoir simulation indicated that 2,000 B/D of water could be injected
through a 1,000 ft. lateral at less than 0.5 psi/ft. The pilot consisted of two
horizontal producers and a horizontal injector between them. The wells were
drilled with a 70 ft. radius, with foam and a horizontal length of 1,000 ft. The
initial results were a disappointing 98 % watercut. Subsequent testing showed
produceable oil saturations only in the top, or rim of the formation and a
parting pressure of 0.35 psi/ft. - less than a column of water. Based on the
newer information, the pilot was reconfigured with two new horizontal wells
drilled in the top of the formation and an existing vertical well turned into an
injector. Oil production increased from 100 to 400 Bopm, turning an economic
failure into a success. Subsequently, an adjacent well was re-entered and
drilled horizontally 350 feet. This well, originally drilled in 1914, is
producing 48 Bopd with 180 Bwpd.
Four other cases were covered briefly. Case A is a medium radius horizontal well
drilled for a DOE project in 1991. It was drilled in the Bartlesville sand,
which was fully developed by 1925 and produced over 30 million barrels of oil.
New vertical wells in the field are not economic. The well was drilled to a true
vertical depth of 1400 feet at a horizontal length of 1,000 ft. between two rows
of depleted producers. The well ended up costing $150,000 - 4.3 times the cost
of an unstimulated vertical well and 2.7 times a stimulated vertical well. The
initial stabilized production was 6 barrels of oil and 1 barrel of water per day
- a 200% to 600% increase when compared to the unstimulated vertical well. It
was considered a technical success and an economic failure. One lesson learned
was that the horizontal length could have been doubled for very little
incremental investment. Most of the cost is in drilling the curve. Used bits
presented problems as well.
Project B was an eight well short radius program in the Tucker formation at
1,300 feet. Early wells were mostly uneconomic, but with information and
experience the later wells were all economic. Project C, like the Grand
Resources, Inc. project, was a pilot attempt to waterflood the Bartlesville sand
in Tulsa County with three medium radius horizontal wells with a horizontal
reach of 1,500 feet. They experienced a significant amount of fluid loss and
suffered well damage. The project was unsuccessful. Project D was a 1988 single
well re-entry in Great Bend, Kansas. A 178 foot horizontal section was drilled
and completed in the Marmaton formation. It was predicted to produce 25 barrels
of oil daily, but only produced six and was considered a failure. It has since
produced 60,000 barrels of oil - 6 times more than the average vertical and is
now viewed as a success.
Bob Westermark
Grand Directions, LLC
2448 East 81st Street, Suite 4040
Tulsa, OK 73149
Phone: 918-492-2366
Email:
bob@grandoil.com
For information on PTTC’s North Midcontinent Region and its activities contact:
Rodney R. Reynolds, Project Manager, Kansas University Energy Research Center
1930 Constant Ave., Lawrence, KS. 66047-3726
Phone: 785-864-7398, Fax: 785-864-7399, Email:
rreynolds@ku.edu
Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.
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