Gas Production Technology

TECHNOLOGY FOCUS

Gas Production
Technology

It was not long ago that finding a natural-gas field beneath your property was Scott J. Wilson, SPE, is a Senior Vice
viewed universally as a stroke of good luck. Now, local natural-gas development President of Ryder Scott Company. He
is feared by many who assume the “new technology” of “fracing” is environ- specializes in well-performance predic-
mentally harmful. In reality, the first hydraulic-fracturing treatment was tested tion and optimization, reserves apprais-
in a North Carolina granite quarry way back in 1903. Hydraulic fracturing has
been used successfully in more than a million wells since then, and, currently, als, simulation studies, software develop-
hundreds of fracturing stages are pumped every day. Very impressive for a ment, and training. Wilson has worked
“new” technology! in all major producing regions in his
Partly because of these very successful and trouble-free wells, natural gas has 25-year career as an engineer and con-
enjoyed an enviable reputation as a clean, cheap, and abundant energy source. sultant with Arco and Ryder Scott. He is
However, we need only to look to the nuclear industry to see that a hard-won
Cochairperson of the SPE Reserves and
reputation can be ruined by false rumors, isolated incidents, or the worst exam-
ples of safety, environmental, and reporting practices. If we always strive to be Economics Technical Interest Group and
good neighbors in the communities in which we work, we can remain proud serves on the JPT Editorial Committee.
natural-gas producers for years to come. Wilson holds a BS degree in petroleum
Because stimulated wells make up an increasing portion of supply with each engineering from the Colorado School
passing year, we have become dependent upon wells that require additional of Mines and an MBA degree from the
attention and often exhibit high decline rates. To buffer the supply/demand
swings, gas-storage wells are used for both injection of dehydrated pipeline gas University of Colorado. He holds two
and production of newly saturated formation gas. Water-vapor equilibrium will patents and is a registered professional
reduce the water saturation around injection wellbores but may increase salt engineer in Alaska, Colorado, Texas,
precipitation in the same region. A new study from the Middle East describes a and Wyoming.
means of maximizing sand-free gas-production rates from wells in unconsolidat-
ed zones, without a difficult-to-place hydraulic fracture. A third paper describes a
means of identifying well candidates that may need a second treatment because
of deterioration of the original fracture or the need to access additional reservoir.
A downloadable full-length technical paper provides a new decline-curve func-
tional form that can match unconventional wells with long transient-flow peri-
ods while honoring late-time interference and depletion. These papers provide
some legitimately new technology. JPT

Gas Production Technology additional reading available
at OnePetro: www.onepetro.org
SPE 137748 • “Rate-Decline Analysis for Fracture-Dominated Shale
Reservoirs” by Anh N. Duong, ConocoPhillips. (See SPE Res Eval & Eng,
June 2011, page 377.)
SPE 142283 • “Effect of Water-Blocking Damage on Flow Efficiency and
Productivity in Tight Gas Reservoirs” by Hassan Bahrami, Curtin University,
et al.
SPE 139260 • “Production Allocation in Multilayer Gas-Producing Wells Using
Temperature Measurements (by Genetic Algorithm)” by Reda Rabie, SPE, Cairo
University, et al.

94 JPT • NOVEMBER 2011

GAS PRODUCTION TECHNOLOGY

Flow-Assurance Challenges in Gas-Storage
Schemes in Depleted Reservoirs

Injection or production of dry gas into or surface facilities, resulting in corro- rium. Generally, producing this amount
or from a depleted gas reservoir could sion, hydrate, and/or ice formation. of water from the reservoir results in
result in serious flow-assurance chal- an increase in the salt concentration
lenges. Parameters involved in water Background (hence, a reduction in water-vapor pres-
evaporation/production and in salt pre- The study model was a 3D, Cartesian- sure and in water evaporation/produc-
cipitation for a gas-production/-injec- grid-type block containing one well. tion). However, it is challenging to
tion well are described quantitatively. The model was intended to represent model this salt-deposition phenomenon
The terms of formation damage (skin) a portion of a gas field (i.e., drainage with commercial simulators.
were evaluated, and some recommen- area) with its corresponding producer/ During injection/production cycles, a
dations for prediction and mitigation injector. A seasonal natural-gas storage/ constant water-production-rate increase
are proposed. Water in the produced production scheme was modeled. First, was observed that corresponded to
gas is a major flow-assurance threat production from the reservoir lasted the constant-rate-vaporization period.
because of the possibility of gas-hydrate 30 months with a maximum daily gas- During this period, it is assumed that
formation in the production system. production rate of 45×106 m3/d. Then, gas is in contact with connate water
Mitigation methods are presented. injection was modeled for 3 months at and that the rock surface is saturated;
10×106 m3/d, followed by 4 months of therefore, vaporization continued until
Introduction soaking (i.e., shut-in). Then, for 5 years the falling-rate period occurred. During
Gas injected into the depleted reser- the following injection/production cycle the falling-rate period, the rock surface
voir normally is a processed/dried gas. was used: 2 months of production, 3 was no longer saturated; therefore, the
However, after injection, the gas is in months of soaking, 3 months of injec- evaporation rate and water-production
contact with hydrocarbon and aqueous tion, 4 months of soaking, and 2 months rate decreased.
phases in the reservoir. Therefore, the of production, for each calendar year.
composition of the produced gas may The following properties were Salinity. Constant salinity was con-
differ from that of the injected gas. More assumed: Reservoir temperature= sidered throughout the entire produc-
importantly, the produced gas will have 104°C, initial reservoir pressure= tion period to predict the maximum
some water (mainly in the form of vapor 250 bar, average porosity=10%, hori- water production for hydrates preven-
at reservoir conditions) because of the zontal permeability in x- and y-direc- tion and to determine inhibitor dosage.
contact with water in the formation. tion=100 md, vertical permeability= During gas injection/production, a por-
During production, the water is produced 10 md, reservoir thickness=110 m, and tion of connate water is evaporated for
with the gas. The net result is evaporation reservoir dimensions of 900×900 m. thermodynamics equilibrium, which
of water from formation brines, result- Connate-water saturation was increases with increasing gas rate and
ing in an increased formation-water salt assumed to be 10%, with a gas/water with pressure decline. Higher forma-
concentration in the reservoir and salt contact at 1005-m depth. The reservoir tion-water salt concentration tends to
formation/deposition. Also, the produced gas was assumed to comprise four slow the rate of evaporation; therefore,
water may condense in the wellbore and/ main components: methane (highest less water is produced.
concentration), ethane, carbon diox-
This article, written by Senior Technology ide, and water. The injected dry gas Capillary Pressure. Assuming a water-
Editor Dennis Denney, contains highlights was assumed to have no water (i.e., 0% wet system, if an aquifer is in contact
of paper SPE 146239, “Flow-Assurance humidity). A modified Peng-Robinson with the reservoir, the capillary pres-
Challenges in Gas-Storage Schemes equation of state was used in the simu- sure effect will increase the amount
in Depleted Reservoirs,” by Alireza lation calculations. of liquid water produced because the
Kazemi, SPE, and Bahman Tohidi, water moves through small pores hav-
SPE, Hydrafact Ltd., and Emile Bakala Water Production. As pressure declines ing the highest capillary pressure. The
Nyounary, Heriot-Watt University, pre- during initial field production, gas higher the capillary pressure, the high-
pared for the 2011 SPE Offshore Europe expands, rock is compacted, and water er the produced-water rate.
Oil and Gas Conference and Exhibition, solubility in the gas increases, resulting
Aberdeen, 6–8 September. The paper has in more connate water being evapo- Gas Velocity (Gas Rate). An increase
not been peer reviewed. rated to satisfy thermodynamic equilib- in gas injection/production from

For a limited time, the full-length paper is available free to SPE members at www.jptonline.org.

JPT • NOVEMBER 2011 95

10×106 to 15×106 std m3/d results in tion damage. However, if a large aquifer 200 m, the effect on gas production and
a 10% increase in the total water pro- support does exist, then the produced water production was negligible.
duced at the end of 91 months of the water will be water from evaporation
injection/production cycle (2550 m3 vs. plus liquid water from water influx. Dynamic Flow
2315 m3). This observation indicates When considering capillary pressure Natural-Depletion Phase. As the pres-
that a higher evaporation rate will occur in the model, with or without existence sure decreases while gas is produced
in the vicinity of the well and near per- of an aquifer, water is produced along by natural depletion, the molar fraction
forations, where the highest gas velocity with gas at each gas-production period of water in the gas phase increases.
will be encountered (resulting in higher during the five injection/production Also, the increase in evaporation will
pressure drops). Nevertheless, a higher cycles. The total amount of water evap- cause salt deposition in the formation,
gas velocity leaves less time for equi- orated and produced, resulting in salt and the salt precipitation will partially
librium; thus, there will be less water transport in the near wellbore region, reduce the pore-throat cross-section-
evaporation. Further, this higher evapo- will depend strongly on the magnitude al flow area, increasing the local gas
ration rate is likely to occur locally, in of capillary pressure. velocity and, consequently, the evapo-
the pore throats, where some reduction ration rate. In radial flow toward the
in permeability has happened because Near-Wellbore Effects wellbore, these phenomena combine,
of salt precipitation. A realistic option is to assume that leading to a more-severe halite deposi-
most of the water evaporation is likely tion near the wellbore and perforations.
Salt-Induced Skin to occur in the near-wellbore region,
By examining the total-water-produc- which will experience maximum for- Dry-Gas-Injection Phase. As dry gas is
tion graphs from previous studies, if no mation damage. As water is produced injected into the formation, it contacts
or a weak aquifer exists, then most of (evaporated) the deposited salt reduces connate water. The result is evapora-
the produced water could be assumed the permeability in the evaporation tion of some of the connate water. This
to be from evaporation. This situation area. It was observed that because the process is driven mainly by the velocity
could be similar to a well completed far zone of evaporation is close to the of the gas and its relative humidity.
from the aquifer or in a large gas res- wellbore (e.g., 150 m from wellbore),
ervoir during the early gas-production the effect on gas productivity was more Soak Phase (Shut-In). When the well
stage during which no water influx severe (i.e., 25% less gas production is shut in for a prolonged period of time
occurs in the reservoir. These situations for the 150-m zone). However, when after gas injection, some of the gas will
could lead to salt deposition and forma- considering a radius of approximately dissolve in the water, and the molar water

West Virginia University
College of Engineering and Mineral Resources - Department of Petroleum and Natural Gas Engineering

The Department of Petroleum and Natural Gas Engineering (PNGE) at West Virginia University invites applications and nominations for two tenure-
track faculty positions at the level of Assistant or Associate Professor. Applicants must have an earned Ph.D. in petroleum engineering and or
natural gas engineering or a closely related field, and the ability to provide teaching excellence in a variety of petroleum engineering courses, both
at the graduate and undergraduate levels. The department values intellectual diversity and demonstrated ability to work with diverse students and
colleagues. Both positions are expected to be filled on or after January 1st 2012.

Drilling and Completion
The successful candidate for this position is expected to develop an active, externally sponsored research program in the area of Natural Gas
Recovery from Unconventional Reservoirs, with an emphasis on drilling and completion in Marcellus shale.

Enhanced Oil Recovery
The successful candidate for this position is expected to develop an active, externally sponsored research program in the area of Enhanced Oil
Recovery.

West Virginia University is a comprehensive land grant institution with medical, law, and business schools, over 29,000 students, and has Carnegie
Doctoral Research Extensive standing. The PNGE Department has 5 faculty members, approximately 200 undergraduates, and 45 graduate
students. The Department offers B.S. (PNGE), M.S. (PNGE), and doctoral degrees. The College has seven departments, over 3,000 students, 120
faculty, and approximately $25 million in research expenditures per annum. The University is located within a growing high technology corridor that
includes several federal research facilities as well as the West Virginia High Technology Consortium. Morgantown and the vicinity have a diverse
population of about 62,000, and is ranked as one of the most livable cities in the country. The city is readily accessible and is within driving distance
from Pittsburgh, PA and Washington, D.C.

Candidates should submit current curriculum vitae, names and addresses of three references, a one page summary statement describing
qualifications for the position, and plans for teaching and research. Review of applications for both positions will start on September 16th, 2011.
These positions will remain open and applications will continue to be reviewed until appointments are made.
Send inquiries and applications to:
Dr. Aminian
Chair, Faculty Search Committee
Department of Petroleum and Natural Gas Engineering West Virginia University is the recipient of an NSF ADVANCE Award
West Virginia University for gender equity.
P.O. Box 6070 WEST VIRGINIA UNIVERSITY IS AN AFFIRMATIVE ACTION/EQUAL
Morgantown, WV 26506-6070 OPPORTUNITY EMPLOYER


content in the gaseous phase will be at a Economic Implications. Assuming an a significant role with respect to water
maximum. After pressure/temperature arbitrary hydrate-inhibitor dosage of 1% production and amount of inhibitor
stabilization, some of the water in the of the produced-water volume, hydrate- required to prevent hydrate formation.
gas phase may recondense, increasing control-cost comparisons were carried out • Salt precipitation will reduce pore-
the water saturation in the near-wellbore for different water-production scenarios. throat size, resulting in less gas and
region. This recondensation could redis- • An increase of formation salinity water being produced.
solve some of the deposited salt. When from fresh water to brine resulted in Comparing systems with and with-
production is resumed after the soak- 7.5% reduction in hydrate-control cost. out salt precipitation showed a 19%
ing period, salt precipitation will occur • The inhibitor cost when consider- reduction in water production in the
because of pressure drop and water evap- ing moderate capillary pressure was case with salt precipitation and, conse-
oration in the near-wellbore region. 10 times that for the zero-capillary- quently, a hydrate-inhibitor-cost reduc-
pressure case. Capillary pressure plays tion of 19%. JPT
Production-After-Soaking Phase.
Generally, the same production phe-
nomenon occurs in this stage. But
the produced water is a combination
of water in gaseous phase from previ-
ous evaporation (dry-gas injection) and
water evaporated because of pressure
drop. However, as gas is produced, the
salt saturation increases in the near-well-
bore region because of evaporation. This
process could result in water migration
to the near-wellbore region because of
the concentration difference. This ten-
dency is greater when a communicating
aquifer exists.

Reducing Halite Deposition. To reduce
salt precipitation during dry-gas injec-
tion/production, freshwater stimulation
on regular basis is recommended because
salt is highly soluble in water. Regular
water washing will help dissolve salt pre-
cipitates in the near-wellbore region and
perforations. Also, the use of long perfo-
ration intervals rather than deep perfora-
tions is recommended. This method will
increase the interface between formation
and wellbore and, therefore, lessen the
flow restriction. Reducing the pressure
drop in the near-wellbore region by any
means is the main objective.
Formation fracturing could be used to
bypass the damaged zone. The fracture
would provide wider flow paths that
would reduce the gas velocity to the well-
bore and provide a larger well/formation
interface. Consequently, the water-evap-
oration rate and salt precipitation could
be reduced in the near-wellbore region.
Whatever abrasive, high-pressure, high-
Natural-Gas Hydrates volume operation you have planned
for your completion, you’re going to
Water produced during gas withdrawal want packing that’s up to the task.
may condense in the wellbore, tubing, Our well service packing solutions are
and surface facilities and may cause cor- engineered to keep you up and running
through it all. Count on us.
rosion or formation of hydrates and/ www.TuffBreed.com
or ice. The amount of hydrates formed
and/or inhibitor required is a function
of the amount of water in the system.
Therefore, it is important to predict the
amount of water in the system for design-
ing prevention techniques/facilities.



Achieving Solids-Free Gas-Production Target Rate From
Highly-Unconsolidated-Sandstone Formation Intervals

One of the most challenging aspects of
producing wells drilled in the uncon-
solidated pre-Khuff gas reservoirs in
Saudi Arabia is to achieve solids-free
production while trying to achieve
high gas rates. Challenging reservoir
conditions include high temperature
and pressure, high stress, heterogene-
ity, and the absence of stress barriers
that together make placing fracture
treatments very difficult. Stand-alone
screens were installed in openhole
well completions in the sandstone res-
ervoir and achieved excellent results
by eliminating the need for a fractur- Fig. 1—Casing and surface-equipment damage caused by formation-
sand production.
ing treatment.
angle and increased-contact wells, and, cementation and diagenesis-controlled
Introduction more recently, sand-screen comple- cementation also play a role. These
Achieving solids-free production from tions have been used to develop these reservoir-quality-influencing factors
unconsolidated-sandstone reservoirs is gas reserves. Among these approaches, are, in turn, subject to sedimento-
an ongoing challenge. The importance the sand-screen completions, in both logical and diagenetic processes, con-
of effective sand control in these wells vertical and high-angle wells, was field trolled largely by the depositional set-
is the need to maintain the integrity tested in two wells, and then it was ting. Porosity and permeability of the
of bottomhole and surface processing implemented in more wells after the gas-bearing intervals vary over a wide
equipment and facilities, and to ensure success of the pilot. range. The well-plan metric for the
that production targets are met consis- initial gas-production rate from the
tently. Fig. 1 shows examples of the Formation Geology formation is from 15 to 20 MMscf/D.
potential damage that sand production The sandstone formation in which the Although this rate is achievable, given
can cause. two well pilot tests were conducted is a the permeability and pressure char-
Several approaches including indirect siliciclastic formation in the pre-Khuff acteristics of the reservoir, the forma-
hydraulic-fracturing stimulation, high- stratigraphic section in Saudi Arabia. tion’s unconsolidated nature increases
Gas resources are in sandstones of the risk of exposing equipment to
This article, written by Senior Technology variable quality within a sequence of damaging sand production.
Editor Dennis Denney, contains high- sandstones, siltstones, mudstones,
lights of paper SPE 141878, “Achieving and shales. Because the formation was Screen Selection
Target Solids-Free Gas Rate From Highly- deposited in a shallow marine tidally Optimum screen selection was achieved
Unconsolidated-Sandstone Formation influenced shoreline setting, it is het- after implementing a series of tests.
Intervals,” by Nahr Abulhamayel, J. erogeneous in character.
Ricardo Solares, SPE, Walter Nunez, Heterogeneity imposes both verti- Sieve Analysis. Several core samples
Ataur Malik, SPE, Mustafa Basri, cal- and lateral-distribution variability were cut and dried in an oven at 185°F
SPE, and Andrew McWilliams, Saudi of reservoir-quality properties over a to make sure that any water in the
Aramco, and Oumer Tahir, SPE, and wide range of scale and geometry. samples was removed. Each sample
Mohammad Abduldayem, SPE, Reservoir quality in this sandstone was gently ground with a rubber mor-
Weatherford, prepared for the 2011 formation is a function of several fac- tar to break up lumps of particles.
SPE Middle East Oil and Gas Show tors, particularly grain size and sort- Approximately 100 g of the ground
and Conference, Manama, Bahrain, ing and clay type and content, which material was weighed, then 12-, 14-,
20–23 March. The paper has not been are controlled largely by the primary 16-, 18-, 20-, 25-, 30-, 35-, 40-, 45-, 50-,
peer reviewed. sedimentological process. Sandstone 60-, 70-, 80-, 100-, 120-, 140-, 170-,



hole section. The completion string
used 41/2-in. super-13Cr standalone
screens similar to that shown in Fig. 2.

Screen-Deployment
Standalone-screen installations in pilot
Well X and pilot Well Y were trouble-
free operations. Predeployment torque-
and-drag modeling results showed that
the screens and other components of
the bottomhole assembly (BHA) could
be deployed without the risk of helical
buckling. The modeling runs indicated
that 25,000 lbm of maximum slackoff
weight could be applied at any stage
Fig. 2—Sand-screen construction. of screen deployment if required, and
that if any obstruction was found in the
200-, 230-, 270-, 325-, and 400-mesh- emulated a collapsed-annulus scenario openhole wellbore, the string had to be
size sieves were used to determine the with sand packed around the screen. picked up and redeployed because no
distribution of particle sizes. Most of rotation was allowed.
the particle retention was in the 40- to Filter-Cake Flowback Test. A filter- Before deploying the screens, the
70-mesh pans. cake flowback test ascertained whether 7-in. casing in each well was scraped
the mud cake that formed in the well- and dressed to eliminate the risk of
Sand-Retention Tests. Sand-retention bore during drilling operations was able tearing or damaging the screens by burs
tests (slurry and sandpack methods) to pass through the screens at normal or debris, and to avoid problems with
were performed after completing the flowing conditions. Test results indi- setting and sealing the packer against
sieve analysis. The slurry method cated that the optimum aperture size the casing. A check trip also was per-
emulated the annular space between for the screens for the two pilot wells formed to ensure that the screens were
the wellbore wall and the outer wall was 300 µm. Both wells were completed able to reach the required depth, given
of the screen. The sandpack method with a 7-in. liner and a 57/8-in. open- that the maximum slackoff weight was

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limited and that circulating through the depth was reached, a 13/4-in. alumi- • Upon reaching total depth, it is
screens rarely helps to wash a string num ball was dropped to plug the drill- important to circulate drill cuttings
deeper. Therefore, the check trip was string, and the liner hanger was actu- out of the wellbore, back ream to the
performed by running a string down to ated hydraulically. Then, the pressure casing shoe, and perform a check trip
a depth where the outer diameter (OD) was increased gradually to 2,500 psi before deploying the screens, to elimi-
of the BHA was larger than the OD of to set the packer, and was increased to nate possible problems.
the screen shoe. The string reached 4,000 psi in increments to energize the • Friction factors should be calibrat-
total depth in both wells without need- packing elements as much as possible. ed with the actual loads experienced
ing to ream or pump, indicating that Packer integrity was confirmed with a during the reaming run.
the screens could be deployed without 10,000-lbf overpull test, a 10,000-lbf • Ensure that solids-free mud is used
any problems. slackoff test, and a 2,500-psi annulus- by checking the shakers frequently to
During screen deployment, wellbore pressure test. confirm that they are filtering the mud
fluids were monitored constantly to properly.
ensure that they were clean and free of Well Performance • Newly mixed mud sometimes is
any particles that could plug the screen, Deliverability tests showed that both sheared insufficiently and has poor
thereby minimizing the risk of screen wells performed above expectations. carrying capacity. The mud will have
collapse. Subsequently, fresh solids- Well X flowed at a sustainable con- to be sheared properly before deploy-
free mud was spotted in the open- trolled gas rate of 22 MMscf/D with a ing the screens; because this can take
hole section ahead of the deployment flowing wellhead pressure of 2,400 psi considerable time, this time must be
operation and a high-rate circulation and no skin damage. Well Y flowed factored in during the planning of the
was performed. at a sustainable controlled gas rate of drilling operation.
The weight of the string was moni- 22 MMscf/D with a flowing wellhead • Proper torque-and-drag modeling
tored carefully during the deployment pressure of 2,425 psi and skin damage must be performed to be fully aware of
operation, and when the BHA reached of less than 1.0. the maximum allowable weight dur-
the targeted depth, its last upward ing deployment of the screens.
movement was recorded to keep it in Lessons Learned Implementing the actions listed above
tension. The setting depth of the liner • Adhering to the directional-drill- will minimize skin damage across the
hanger and the liner-top packer was ing plan is critical to limit the dogleg screens, which in turn will reduce the
selected taking into consideration the severity and to ensure that screens can pressure drop across the completion
liner-couplings depth. Once the setting be deployed trouble free. and maximize production rate. JPT

SPE Middle East Unconventional Gas
Conference and Exhibition
Unlocking Unconventional Gas:
New Energy In the Middle East

23–25 January 2012 | Abu Dhabi, UAE
www.spe.org/events/ugas

Society of Petroleum Engineers


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amount of proppant required and improve efficiency. In addition, the
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Screening Method To Select Horizontal-Well
Refracturing Candidates in Shale-Gas Reservoirs

A method was developed to screen total well population that represents will result in good production perfor-
potential horizontal-well-refracturing high potential for restimulation suc- mance, for which the degree of depar-
candidates rapidly by use of produc- cess. However, it also was determined ture from the optimum parameters is
tion performance and completion- that industry’s current experience with translated as a proxy for restimulation
data analysis. Integration of initial restimulation is mixed, and that con- potential. Virtual-intelligence tech-
hydraulic-fracture-completion details siderable effort is required in candi- niques can be designed to mimic the
augments the process and helps date selection, problem diagnosis, and thinking process of a completion engi-
screen understimulated wells in dif- treatment design/implementation for a neer who is entrusted with selecting
ferent production classes. To accom- program to be successful. refracturing candidates. The downsides
plish this screening, an index called a The GTI study investigated three are the data and expertise require-
“completion index” was defined after main classes of candidate-selection ments. Expert judgment is required in
analysis of the completion param- methods: production-performance conditioning data to be used in the var-
eters, production behavior, and their comparisons, pattern-recognition-tech- ious processes, and the outcome could
interrelationship. nology/virtual-intelligence methods, be compromised by lack of important
and production-type-curve matching. information, such as reservoir proper-
Introduction The study concluded that although ties. Selection based solely on produc-
Restimulation of existing wells rep- virtual-intelligence methods were relation data will have the same limita-
resents a vast unexploited resource tively better compared to production tions faced in tight sands, although
in tight formations. In 1996, the type curves, no universal method exists production data are a critical input for
Gas Research Institute, now the Gas that enables selecting restimulation the other two methods. Hence, there
Technology Institute (GTI), investi- candidates across different geologic set- is a need for specific methodologies
gated the potential for natural-gas-pro- tings. Use of production statistics alone for refracturing-candidate selection in
duction enhancement by use of restim- was the least-effective process. shale reservoirs.
ulation in the USA (onshore, lower Most of the literature referencs ver-
48 states). The report indicated that tical wells in layered formations of Rationale of Refracturing
the potential was substantial (more tight-sand reservoirs. Although the and Candidate Selection
than 1 Tcf of reserves in 5 years), par- same candidate-selection methods The rationale is to attain a stimu-
ticularly in the tight gas sands of the can be extended to horizontal wells in lated-reservoir volume greater than
Rocky Mountain, midcontinent, and shale-gas reservoirs, limitations exist. that achieved in the initial fractur-
south Texas regions. The study also The production-type-curve-matching ing treatment. When a new volume
stated that 85% of the restimulation method typically is not applicable in a of shale is exposed in a refracturing
potential for a field exists in 15% of shale-gas setting because of variability treatment, the stimulated-reservoir vol-
the wells. Hence, the key to any suc- in complex fracture networks from well ume is enlarged, resulting in a gain in
cessful restimulation program is being to well and lack of diagnostic tools for reserves. A potential refracturing can-
able to identify that 15 to 20% of the quantifying fracture characteristics for didate is one that is performing below
analysis. Pattern-recognition or virtual- its productive potential with respect to
This article, written by Senior Technology intelligence methods have limitations in-situ reservoir characteristics despite
Editor Dennis Denney, contains highlights mainly from the amount, type, and initial hydraulic fracturing. Therefore,
of paper SPE 144032, “A Novel Screening quality of data available for robust anal- to identify potential candidates, res-
Method for Selection of Horizontal- ysis. Ideally, an adequate and complete ervoir characteristics need to be sepa-
Refracturing Candidates in Shale-Gas data set (including completion and rated from hydraulic-fracture charac-
Reservoirs,” by Shekhar Sinha, SPE, reservoir/geology data) that quantifies teristics. Generally, underperformance
and Hariharan Ramakrishnan, SPE, successful cases of horizontal refractur- of shale-gas wells can be caused by
Schlumberger, prepared for the 2011 ing in shale should be available to train inefficient initial completion, inefficient
SPE North American Unconventional the virtual-intelligence tools. Pattern- well placement, gradual damage during
Gas Conference and Exhibition, The recognition tools use artificial neural production, or pressure depletion.
Woodlands, Texas, 14–16 June. The networks to extract a set of optimum A refracturing-candidate-identifica-
paper has not been peer reviewed. completion parameters that most likely tion workflow should honor both



Fig. 1—3D Earth model produced from integrating Fig. 2—Gas-porosity log extracted from the 3D model
seismic, log, and geological data. along a horizontal lateral.

production potential of the reservoir are used for comparing production in the laterals. Staging has been as close
rock and major causes of underper- between wells. The production indica- as 270 ft in Barnett shale completions.
formance. The method detailed in the tor should represent long-term pro- Consistent staging data are difficult to
full-length paper has two tiers. The duction behavior. Estimated ultimate find in public databases; therefore, only
first tier is a purely statistical short recovery (EUR) would be the best a few operators’ data sets were con-
listing of candidates by use of both production indicator, but for horizon- sistent enough to use for completion-
production-performance comparisons tal wells in shale reservoirs, EURs often index calculation.
and initial-completion details. The sec- are subjective and change as additional Depending on shale-reservoir char-
ond tier is model based and integrates production data become available (i.e., acteristics (e.g., heterogeneity and
the first tier of statistical analysis with prolonged linear-flow behavior and presence of natural fractures), the cor-
available petrophysical data and geo- absence of boundary-dominated flow relation between individual comple-
logical information. in the available production history). tion variables and the production indi-
Often, the first-12-month gas produc- cator varies. Therefore, the completion
Candidate-Selection Workflow tion or best-12-month gas production index for a specific shale play must
Data Requirements. Production and will correlate well with longer-term be defined for wells being studied in
completion data for this study were production (5- or 10-year cumulative the area of interest after studying the
taken from the public domain. The production) and can be used as a proxy correlation of individual completion
data from these sources can be import- for long-term production. and stimulation parameters vs. pro-
ed into any database application or Completion Indicators. Evolution of duction indicators. The completion-
spreadsheet program to perform the completion practices in shale reser- index definition and calculation used
analysis. Monthly oil-, gas-, and water- voirs has had a significant effect on here are based on the data set used and
production data were available from production performance. Many of the on available public completion data.
these sources, as reported to regulatory early foam and gel completions in the Internal to an operating company, a
agencies. Reported-completion-data Barnett shale have been restimulated more complete data set would be avail-
quality in the public domain is some- with slickwater, which has become able and analyzed to formulate the
times inconsistent and requires strin- the standard treatment. Large slick- applicable completion index.
gent quality checks before proceeding water completions have been shown For the given data set, the simplest
for analysis. to develop very large and complex completion index can be computed
fracture-network systems, resulting by combining three completion vari-
Production, Completion, and Reser- in higher production rates compared ables—total volume pumped, number
voir-Quality Indicators. The first tier with other fluid types. Supplementing of stages, and length of the lateral—
of data analysis is statistical and uses production-data analysis with com- as follows.
production indicators and completion pletion data enhances the candidate-
indicators derived from initial-com- selection process and provides valu- Completion Index=
pletion details. This step reduces the able insights by identifying patterns of
Total volume of fluid pumped
number of potential candidates for use completion practices and their effect .
in the second-tier analysis. First-tier on production performance. (Lateral length/Total number of stages)
data analysis will yield results similar to An important development in hor-
those of pattern-recognition methods. izontal-well fracturing has been mul- If only one variable shows a clear
Production Indicators. Time-norma- tistage fracturing. There has been an dominant correlation to production,
lized production indicators often evolution to a larger number of stages then that variable alone can be rep-


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resented as the completion index. A to the hydrocarbon-in-place potential. reservoir-quality, tends to reduce and
simple completion index could be total The reservoir-rock-quality definition trends are more noticeable.
volume of fluid pumped, volume of also can consist of rock-mechanical To determine whether completion
fluid per unit length, or total proppant properties that define the fracturabil- or reservoir quality has more effect
placed. Once a completion indicator ity of the rock, which enables cre- on production, the production index
is defined, it is used as an indicator of ation of large fracture-surface areas in was crossplotted with the completion
overall hydraulic-fracture-completion the reservoir. index, and the reservoir-quality index
quality of the well. For an area of Most operators in different shale and correlation coefficients were com-
interest with relatively uniform res- plays drill multiple pilot wells and pared. Wells that are out of zone are
ervoir-rock characteristics, a positive perform complete suites of logs for clustered together and have no correla-
correlation between computed com- evaluation. These pilot-well logs can tion, while wells landed in the target
pletion index and production index is be integrated with available logs from zone have a much better correlation.
expected with a lower degree of scat- laterals, logging-while-drilling data, For the analyzed data set, the cor-
ter, but the objective of crossplots is to seismic data, and geological data to relation between production index and
use the correlation as a candidate-well build an integrated reservoir model. reservoir-quality index was stronger
filtering tool, as explained in the next The integrated reservoir model cap- than that between production index
subsection, not to derive the correla- tures structural and reservoir-proper- and completion index. Out-of-zone
tion coefficient. ty variations between the pilot wells wells showed a slight trend with res-
Reservoir-Quality Indicators. One by integrating data from all sources, ervoir-quality index, but no trend with
of the main factors for scatter observed as shown in Fig. 1. From the model, completion variables. Also, out-of-
on correlation graphs of production synthetic logs along the horizontal zone wells had poor overall comple-
and completion variables alone is the laterals, as shown in Fig. 2, can be tion quality. In general, reservoir qual-
variation of reservoir-rock character- extracted and used as proxies for ity had a greater effect on production
istics in these reservoirs. Reservoir- reservoir-quality indicators. When the potential compared with the effect of
rock quality can be defined by several variability in reservoir quality is nor- completion variables. For uniform res-
properties, such as hydrocarbon-filled malized, scatter in the observed rela- ervoir quality, the production indicator
porosity, pore pressure, and organic tion between production and com- would correlate better with comple-
content and maturation, that relate pletion, or between production and tion variables. JPT

STATEMENT OF OWNERSHIP, MANAGEMENT AND CIRCULATION (Required by 39 U.S.C. 3685). 1. Title of publication, Journal of Petroleum Technology. 2.
Publication No. 0028-1960. 3. Date of filing, 26 September 2011. 4. Frequency of issue, monthly. 5. No. of issues published annually, 12. 6. Annual subscription
price, $15. 7. Complete mailing address of known office of publication, SPE, 222 Palisades Creek Drive, Richardson, TX 75080-2040, Dallas County. 8. Complete
mailing address of the headquarters or general business offices of the publishers, SPE, 222 Palisades Creek Drive, Richardson, TX 75080-2040. 9. Name and
address of publisher, Georgeann Bilich, 222 Palisades Creek Drive, Richardson, TX 75080-2040. Name and address of editor, John Donnelly, 10777 Westheimer,
Suite 1075, Houston, TX 77042-3455. 10. Owner, Society of Petroleum Engineers (SPE), 222 Palisades Creek Drive, Richardson, TX 75080-2040. 11. Known
bondholders, mortgagees, and other security holders owning or holding 1 percent or more of total amount of bonds, mortgages, or other securities (none). 12.
The purpose, function, and nonprofit status of this organization and the exempt status for Federal income tax purposes have not changed during preceding 12
months. 13. Publication name: Journal of Petroleum Technology. 14. Issue date for circulation data below: September 2011. 15. Extent and nature of circulation:

Average Number Copies Each Number Copies of Single Issue
Issue During Preceding 12 months Published Nearest to Filing Date

A. Total number of copies (net press run) 66,274 68,622
B. Paid circulation (by mail and outside the mail)
1. Mailed outside-county paid subscriptions stated on Form 3541 30,481 31,292
2. Mailed in-county paid subscriptions stated on Form 3541 none none
3. Paid distribution outside the mails including sales through dealers and
carriers, street vendors, counter sales, and other paid distribution outside USPS 34,465 35,967
4. Paid distribution by other classes of mail through the USPS none none
C. Total paid distribution 64,946 67,259
D. Free or nominal rate distribution (by mail and outside the mail)
1. Free or nominal rate outside-county copies included on Form 3541 none none
2. Free or nominal rate in-county copies included on Form 3541 none none
3. Free or nominal rate copies mailed at other classes through the USPS none none
4. Free or nominal rate distribution outside the mail 305 175
E. Total free or nominal rate distribution 305 175
F. Total distribution 65,250 67,434
G. Copies not distributed 1,024 1,188
H. Total 66,274 68,622
I. Percent paid and/or requested circulation 99.5% 99.7%

17. I certify that the statements made by me above are correct and complete. Alex Asfar, Senior Manager Publishing Services.


EGPC

INTERNATIONAL 2011 BID ROUND FOR
PETROLEUM EXPLORATION AND EXPLOITATION

- The Egyptian General Petroleum Corporation (EGPC) invites Petroleum Exploration Companies for
the International 2011 Bid Round to explore / exploit for Oil and Gas in Egypt under the Production
Sharing Agreement.
- The International 2011 Bid Round includes Fifteen (15) Exploration Blocks in Gulf of Suez, Eastern
Desert, Western Desert & Sinai Sedimentary Basins as shown in the map.

(1) (13)
NE OBAYED NW ABU ZENIMA
801.266 KM2 276.3 KM2
(2)
(3)
NORTH MATRUH (14)
798.124 KM2 NW GINDI (11)
1351.16 KM2
E. RAS BUDRAN
E. LAGIA OFFSHORE
(I) 2989 KM2 45.56 KM2
(II)
(5) (8) (15)
(III) N.ALAM EL SHAWISH NW GHARIB NE ISSRAN
565.23 KM2 ONSHORE 343 KM2
(4)
654.98 KM2
S.GHAZALAT
1883 KM2

(9)
SW GHARIB (12)
(6) ONSHORE
(7) EL QA’A PLAIN
195.5 KM2
S. ABU SENNAN 1823.5 KM2
2978.8 KM2 SE ABU SENNAN
3006 KM2

(10)
SE GHARIB
ONSHORE
508.5 KM2

- Interested companies can submit their offers based on the Procedures, Main Commercial Parameters and
the applied Egyptian Production Sharing Model Agreement.
- Data purchasing and data room will be available in EGPC Geological & Geophysical Information
Center, Nasr City, upon request and according to the determined prices.
- Main Information, Coordinates, Procedures, Main Commercial Parameters and the Model Agreement
can be obtained through EGPC site : www.egpc.com.eg
Closing Date: Monday, January 30th, 2012 at 12:00 hrs.

For further information, please contact:
Deputy Chief Executive Ofﬁcer for Agreements
Telephone : (202) 27065358 Fax : (202) 27065887

Gas Production Technology

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