By Scott B. Gill, Simmons and Company International
The worldwide deepwater business, like the rest of our industry, is at a
critical juncture. The opportunities for the industry are huge. Projecting a
15% annual increase in the amount of worldwide exploration and
production spending for five years, the oil service industry will need
another $96 billion in capital over a five year period. How can we grow this
industry? Can the industry experience rational growth or does the industry
continue to experience volatile ups and downs?
Hydrocarbon demand is at an all time high, and is increasing at a rate of 3% per year. The industry must now not only supply the world's insatiable appetite for more hydrocarbons, but must overcome its own nemesis - depletion. First-year depletion rates for natural gas production have risen from 26% in 1991 to 46% in 1996. The industry must replace ever increasing amounts of the prior year's production and then add more supply to meet the incremental demand.
In the midst of true growth for the commodities of oil and gas, our industry has changed from one of chronic excess capacity to one of chronic shortages. Today, supply must come from one source: more drilling. Offshore is the most effective near-term frontier area in which the industry can turn in order to supply the world with the oil and gas it demands and the deepwater sector contains the most prolific reserve and production potential. The problem (or the opportunity) is: we are out of rigs, we are out of equipment, and we are out of people.
450 More Rigs Needed Worldwide
Until two years ago, the excess supply of offshore rigs had been around
for so long that it seemed almost impossible that we could experience a
rig shortage again. Today 33 oil rigs are under construction, but cost for
today's rig is 30% higher than it used to be. The pinch of rig shortages
and the resulting impact it will have on project delays and missed
production targets are just beginning to be felt. We believe that 450 more
offshore rigs will be needed to return the E&P business to rig equilibrium.
In Canada, there might be a need for 250 to 300 additional rigs to merely
create the daily gas volume needed to fill up the pipelines being added to
bring more Canadian gas to the U.S.
Conservative estimates assume that offshore production will grow only 2.3% annually through 2007. Conservative growth rate indicates that an additional 90 offshore rigs are needed to do development and workovers. An additional 60 rigs will be needed to drill at 100% utilization for 10 straight years for to put one well on each Gulf of Mexico lease in over 3,000' of water.
During the peak period of offshore exploration in the mid-1980s , 388 rigs were drilling exploratory wells around the world. This compares to about 200 today. In 2007, the exploratory fleet should be back up to the mid 1980s level and 188 additional rigs will be needed.
Rig Costs: A Challenge
Rig construction cost are not static. We have already seen cost escalate
over 30% in the past two years. During the last construction cycle,
construction costs rose 15% to 22% per year. The bottom line is that day
rates for drilling rigs must go up!
How can we possibly expand when there seems to be a stalemate between the rig contractors who are unwilling build new rigs and E&P companies who do not seem anxious to pay higher day rates? Today's day rates do not justify a return in excess of the cost of capital for new rig construction. Most of the contracts signed this year will barely break even. New construction costs on a semi-submersible rig are estimated at $300 million with delivery scheduled for 36 months in the future. A five year contract at a day rate of $200,000/day does not provide the economics to justify its construction. Who would build a $300 million asset that reaches break even when the business up-cycle may be over?
A 10 Year Need for 71 MMBOE Per Day
There will be a ten-year need for an incremental 71 MMBOE per day. If
the industry has any hope of meeting this goal then there has to be a lot
more drilling. The capacity overhangs from ten years ago have long since
eroded. Gone is the 20 MMBOE per day excess oil capacity, gas bubble,
and the 450 excess offshore rigs of the past The land rig market is
nearing 90% utilization rates. The industry must face the stark reality that
the bubble era is over. With the bubbles of the prior decade gone, the
only means by which we can meet the hydrocarbon demands of the next
decade is to drill.
"This Age of Prosperity" is most seductive and its opportunities enormous. Its lure will also bring this cycle to a halt one day. Oversupply will happen as it always does. Yet, we are in the beginning of a long up-cycle. To grow rationally, the industry must get back to drilling. The industry must focus on getting more production and reserve recovery from its existing fields. The industry must continue to look for and explore future reserves like those in the deepwater Gulf of Mexico. The industry also needs more equipment, and most importantly, more people.
Biographical Sketch:
Scott Gill is currently vice president with Simmons & Company
International. Gill has a B.S. in mechanical engineering from Louisiana
State (1981), and worked for Amoco Production Company in their Gulf of
Mexico operations. While at Amoco, Scott worked in several engineering
capacities, and managed their Gulf of Mexico production engineering
group. Gill served as director of Integrated Solutions for the newly formed
Baker Hughes INTEQ division. He is a registered petroleum engineer and
holds a M.S. in business administration from Tulane University.
Inset Caption: "The problem is: we are out of rigs, we are out of equipment, and we are out of people."
Speaker: Garry D. Jones.
The most fundamental change that the Texas Natural Resource
Conservation Commission (TNRCC) made when it adopted the current
"Risk Reduction Rules" and the "Risk-Based Corrective Action Rules for
Leaking Storage Tank Sites" was the recognition that limited quantities of
pollutants, otherwise known as "chemicals of concern," may remain in
environmental soil, water, and air without endangering human health. The
mere presence of a pollutant in a medium would not necessarily make that
medium contaminated unless the pollutant was at a concentration level
that could pose a substantial threat to human health or the environment.
Most of the rules and associated guidance under the existing Risk
Reduction and Risk-Based Corrective Action rules are directed toward
defining those materials and conditions that would present a substantial
threat to human or ecological receptors.
This approach marked a major departure from the practice of requiring a responsible party either to remove all waste and restore to prior background levels or to contain the materials and perform appropriate post-closure care. The Commission did not adopt a full risk-based program in the existing Risk Reduction Rules because of the historical use of background levels. The current Risk Reduction Rules are hybrids consisting of both background and risk-based considerations.
The TNRCC is proposing to construct the Texas Risk Reduction Program using only risk-based procedures. Under this approach, pollutant concentrations below risk-based thresholds would be below the level of regulatory concern, regardless of background concentrations. The Texas Risk Reduction Program is a proposed rule package that would establish a consistent risk-based corrective action approach for all waste program areas. These new rules will replace the current Risk Reduction Rules and Risk-Based Corrective Action Rules for Leaking Storage Tank Sites. The new rules would also apply to other waste program areas, such as municipal solid waste, which are not presently subject to either of these risk-based rules.
This timely presentation will compare the current and proposed Texas Risk Reduction Rules as they may affect remediation and closure of contaminated sites in Texas. Particular emphasis will be placed on increased corrective action options and their impact on environmental decisions. An example of the practical application of the proposed Texas Risk Reduction Program will be given that highlights the effort Radian has undertaken in evaluating the procedures. This will cover some base assumptions, some of which are documented by the TNRCC, algorithms, and potential pitfalls.
Biographical Sketches:
Toraman Sahin graduated from Cornell
University with a B.S. and M.S. in 1972 and 1973. He has 23 years of
progressive experience in environmental science, regulatory
compliance, closure, permitting, risk assessment, groundwater modeling,
and remediation for both RCRA and CER-CLA sites. He is currently
employed by Radian International, L.L.C. as a project manager. Previously,
he was with DuPont Environmental Remediation Services as the section
manager for the Environmental Group and acting section manager for the
Geological Group.
Jason K. Christian is a staff environmental engineer with Radian International, L.L.C. He holds a B.S. degree in civil engineering and an M.E. degree in environmental engineering, both from Texas A&M University. His work experience includes doing site assessments, risk assessments, and closures for mainly industrial clients.
Exploration drilling since 1994 has resulted in six new Egyptian field
discoveries, four of which are currently producing approximately 40,000
BOPD. Primary production is from the Cretaceous Bahariya and Kharita
sand-stone reservoirs , as is typical in the Western Desert. The area is fast
becoming the newest and largest oil producing province. The Qarun Field
is emerging as the largest and most prolific oil field in the Western
Desert.Qarun Field lies on the southeast flank of the Kattaniya uplift and
the northwest flank of the Cenozoic Gindi Basin 80 km southwest of Cairo.
The Kattaniya uplift is an inverted Mesozoic basin containing thick Middle
Jurassic Khatatba oil-prone source rocks. The oil migrated southeast-ward
to charge Qarun field along a NE-SW trending intrabasinal paleoarch, separating the
Kattaniya inverted basin from the Gindi basin.
The Qarun and Beni Suef oil discoveries lie just south of Cairo, adjacent to the Nile River, within the Qarun and East Beni Suef concessions, in a readily accessible area. The region has been previously explored by Shell, Amoco, Esso, and Braspetro. Seagull Energy International and Apache Corporation are currently exploring in conjunction with the Egyptian General Petroleum Corporation (EGPC).
Qarun Field (A lobe) was discovered in October 1994 by Phoenix Resources Company with partners Apache Corporation and Global Natural Resources (now Seagull Energy). The drilling of the El-Sagha 1-A wildcat encountered oil pay in both Cenomanian Bahariya and Albian Kharita sandstones. The updip El-Sagha 3- X confirmation well encountered over 285 feet of net oil pay in the Bahariya and Kharita sands in a continuous gross oil column over 500 feet thick. The well test-ed at an aggregate rate of 11,957 BOPD of 42° gravity oil. Primary reservoirs are found at depths between 8700 and 9400 feet. The Qarun oil field complex (A, B, and C lobes) consists of two en echelon compressional folds trending northeast and southwest established along the upthrust sides of two faults.
During September 1996, the C-1X well opened up Qarun Southwest Field (C lobe), logging 275 feet of net oil sand in the Bahariya and Kharita formations. The well tested at a combined rate of 4600 BOPD. Also during that month, the Wadi Rayan 1- X wildcat, situated 55 km south of Qarun field on the south flank of the Gindi Basin, tested 950 BOPD of 25° gravity oil from Cenomanian Abu Roash "G" sandstones at 5500 feet. This discovery opens up a new exploration trend in the southern portion of the Qarun concession.
Farther south, 75 km from Qarun field , within the adjacent East Beni Suef concession, the Beni Suef-1-X wildcat tested 40-gravity oil from the Bahariya and Kharita formations at a depth Gallagher Research and Development Company of approximately 7000 feet at an rate of 6976 BOPD during September 1997. This well, operated by Seagull Energy International with partner Apache Corporation, confirms a new productive basin that seismic data indicate extends eastward across the Nile River.
Biographical Sketches:
Michael Nemec received his B.S. in geology
from the University of Houston in 1977. He joined Seagull in 1997 as
Qarun Project coordinator. He has been involved in Western Desert
exploration since 1984 when he was with Phoenix Resources Company.
Gerald Colley is senior vice president international exploration and
production for Seagull Energy Corporation. From 1973 to October 1992
Mr. Colley held a variety of technical and management positions with
several major and independent oil and gas exploration and production
companies including Texaco and Kerr McGee. Colley earned a B.S. in
geology from the University of Exeter, England, and a M.Sc. in geophysics
from the University of Durham, England.
The Val Verde Basin is a southern extension of the Delaware Basin of West Texas that was converted to a fore-land trough during the Late Paleozoic Ouachita collision. This gas-rich basin has historically been known for several multiple-TCF Ellenburger fields trapped in large anticlinal structures. Despite such large reserves, the Val Verde Basin remained under-explored and poorly understood through the 1980s, owing to geologic complexity and seismic imaging problems.
In 1989, successful application of 2-D swath seismic techniques resulted in dramatic improvements in seismic data quality and opened a new phase of exploration in the basin. In 1993, a commercial new field discovery was made in a Pennsylvanian Strawn carbonate reservoir within the thrusted foreland section. Continued exploration and development of the thrusted foreland trend, using 2-D swath and 3-D seismic, led to significant discoveries in a new play: the Thrusted "Penn" Sands.
Conoco and its partners have drilled a total of 45 exploration and development wells in the thrusted foreland trend, and made eight new field discoveries. Gross daily production from these fields aver-ages 65 MMCFD and 2100 BOPD. Structural compartmentalization, stratigraphic variability, diagenesis, and fracturing have created a complex reservoir system. Reservoir quality and quantity are the critical uncertainties. Early in the play, the per well commercial success rate was only about 40%. Successful field development has required the collection and integration of significant amounts of geologic, geophysical, and engineering data . Interpretation of 3-D seismic data, conventional log and image data, core data, and pressure data by a multi-discipline asset team has provided the framework for understanding the depositional and structural complexities of the thrusted foreland reservoirs. As a result, our full-cycle commercial success rate has improved to greater than 70%.
Biographical Sketch:
Barbara Sheedlo is an operating unit supervisor
for Conoco, Inc., in Midland, TX. Barbara received her B.A. and M.A. in
geology from Rice University. Upon graduation in 1984, Sheedlo started
with Conoco in Lafayette, Louisiana , where she worked the
Smackover trend. She subsequently moved to Houston and then to New
Orleans, where she worked shallow and deepwater plays in the Gulf of
Mexico. Sheedlo joined the Midland Division in 1993 as a chief geologist,
and for the last two years has led a multi-disciplinary team charged with
exploration and development of the Val Verde Basin.
Throughout the Tertiary basins in the Gulf Coast, there are areas where
the acoustic-impedance values of shales, wet sands and gas sands are
approximately equal. Hydrocarbon zones do not appear as bright spots
and are difficult to detect with conventional 3-D seismic data. In some
areas, even AVO has not been successful. This difficulty normally occurs
when the rock properties are not calibrated to the various local AVO
attributes.
A 3-D AVO study in the Texas and Louisiana transitional zone has been completed using well log suites, core analyses, and field production histories. Results from this study are illustrated in Figure 1, where a conventional 3-D section is shown in the upper portion. This section is a mixture of both chrono- and litho-stratigraphic reflections. In the bottom portion of the figure, only the litho-stratigraphic reflections are retained.
Correlation of the well log curves and the field production histories to the lower section indicate that all the high-amplitude events are associated with proven hydrocarbon zones. It is obvious that the reflection amplitudes in the upper conventional 3-D seismic section do not identify lithology if the high-amplitude events in the lower litho-stratigraphic section are truly hydrocarbon events.
The basis for unraveling complex AVO responses to various rock types and fluid content is a two-term seismic reflection model. The first term, the Normal Incidence reflectivity (NI), which has historically been related to chrono-stratigraphic reflections, responds to changes in acoustic impedance. The second term, defined as the Poisson Reflectivity (PR), relates to changes in Poisson's Ratio. Unlike NI, PR remains sensitive to litho-logic variations within the geologic environment and is thus associated with litho-stratigraphic reflections. The rock property contrasts, which generate the NI and PR response, become evident by cross-plotting well log values of the natural log of acoustic impedance versus Poisson's Ratio. The crossplots show that even when the sands have the same acoustic impedance as the encasing shales, Poisson's ratio discriminates between them. To obtain a robust estimate of PR from seismic data, the AVO processing incorporates corrections for anisotropy, which extends the AVO analysis out to very - far offset traces. After calibration to log data, the resulting PR sections depict reservoir quality sands and potential pay intervals as litho-stratigraphic sections.
Biographical Sketch:
Fred J. Hilterman, received a geophysical
engineering degree and a Ph.D in geophysics from Colorado School of
Mines. In 1973, he joined the University of Houston, where he was
Professor of Geophysics. While at UH, Fred co-founded the Seismic
Acoustics Laboratory (SAL) and was principal investigator until 1981. At
that time, he co-founded Geophysical Development Corporation where he
is currently vice president of development.
Hilterman just finished his term as the 1996-97 president of the Society of Exploration Geophysicists. He has been associate editor for Geophysics; SEG and AAPG Distinguished Lecturer; chairman of The Leading Edge editorial board; and technical and general chairman of SEG annual meetings. He also teaches in SEG's continuing education courses. Hilterman received the SEG Best Paper award and Best Presentation award, the CSM VanDiest Gold Medal and Distinguished Alumni Medal, the SEG Virgil Kauffman Gold Medal, and honorary membership in SEG and GSH.
