***EXCERPT FROM MMS REPORT, Deepwater Gulf of Mexico 2009: Interim Report of 2008 Highlights***
For purposes of this article, deep water is defined as water depths greater than or equal to 1,000 ft (305 m), and ultra-deep water is defined as water depths greater than or equal to 5,000 ft (1,524 m). A few other definitions are useful at this point:
- Proved Reserves are those quantities of hydrocarbons that can be estimated with reasonable certainty to be commercially recoverable from known reservoirs. These reserves have been drilled and evaluated and are generally in a producing or soon-to-be producing field.
- Unproved Reserves can be estimated with some certainty (drilled and evaluated) to be potentially recoverable, but there is as yet no commitment to develop the field.
- Known Resources refer to discovered resources (hydrocarbons whose location and quantity are known or estimated from specific geologic evidence) that have less geologic certainty and a lower probability of production than the Unproved Reserves category.
- Industry-Announced Discoveries refer to oil and gas accumulations that were announced by a company or otherwise listed in industry publications. These discoveries may or may not have been evaluated by the Minerals Management Service (MMS) and the reliability of estimates can vary widely.
- Field is defined as an area consisting of a single reservoir or multiple reservoirs grouped on, or related to, the same general geologic structural feature and/or stratigraphic trapping condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers or both.
In the late 1990s, a new era for the Gulf of Mexico (GOM) had just begun with intense interest in the oil and gas potential of the deepwater areas. At that time, there were favorable economics, recent deepwater discoveries, and significant leasing spurred on by the Deep Water Royalty Relief Act (DWRRA; 43 U.S.C. §1337). Historically, deepwater production began in 1979 with Shell’s Cognac Field, but it took another 5 years before the next deepwater field (ExxonMobil’s Lena Field) came online. Both developments relied on extending the limits of platform technology used to develop the GOM shallow-water areas.
Fig. 1: Deepwater discoveries by year. Credit: BOEMRE Since then, deepwater exploration and production technology has tremendously advanced. In February 1997, there were 17 producing deepwater projects, up from only 6 at the end of 1992. Since then, industry has been rapidly advancing into deep water, and many of the anticipated fields have begun production. At the end of 2008, there were 141 producing projects in the deepwater GOM, up from 130 at the end of 2007.
Over the last 15 or so years, leasing, drilling, and production moved steadily into deeper waters. There are approximately 7,310 active leases in the U.S. GOM, 58 percent of which are in deep water. (Note that lease statuses may change daily, so the current number of active leases is an approximation.) Contrast this to approximately 5,600 active GOM leasesin 1992, only 27 percent of which were in deep water. There was a maximum of 31 rigs drilling in deep water in 2008, compared with only 3 rigs in 1992. Likewise, deepwater oil production rose about 786 percent and deepwater gas production increased about 1,067 percent from 1992 to 2007. Production from seven deepwater fields began in 2008, including Thunder Horse, the largest daily producer in the GOM.
Ultra-Deepwater Drilling and Discoveries (greater than 5,000 FT/1,524 M)
In 1986, the first discovery in the GOM in water depths greater than 5,000 ft (1,524 m) occurred with Mensa. Since that time, there have been 64 additional discoveries in the ultra-deep provinces of the Gulf. The production from 13 of these discoveries is associated with the Independence Hub natural gas processing facility. Another 15 of the discoveries are associated with the Lower Tertiary trend.
Fig. 2: Estimated volume of proved deepwater fields. Credit: BOEMRE
In 2007, MMS reported a record number of 15 rigs drilling for oil and gas in water depths of 5,000 ft (1,524 m) or more in the GOM. Although this record has not yet been surpassed, MMS expects increased drilling activities in ultra-deep water, with 15 newbuild mobile offshore drilling units (MODU’s) contracted for delivery to the GOM in 2009 through 2011. The MMS expects 2 new drillships and 6 new semisubmersible drilling rigs in 2009, 5 new drillships and 1 semisubmersible drilling rig in 2010, and 1 new semisubmersible drilling rig in 2011. There are also 4 semisubmersible rigs that are currently being
upgraded to drill in ultra-deep water that are contracted for delivery to the GOM in 2009 and 2010. The newbuild Stena DrillMAX I drillship and the Seadrill West Sirius semisubmersible drilling rig were delivered to the GOM in 2008. All of the newbuild MODU’s are being built with dynamic positioning systems and will not have to be moored to the seafloor. These newbuild MODU’s will be capable of drilling in water depths from 7,500 to 12,000 ft (2,286 to 3,658 m) and will be capable of drilling wells from 30,000 to 40,000 ft (9,144 to 12,192 m) below the seafloor. There are several drilling contractors that have MODU’s in construction for delivery in 2010 and 2011 that are not yet contracted with operators, and some of these MODU’s are expected to operate in the GOM under future contracts.
Challenges and Rewards
Significant challenges exist in deep water in addition to environmental considerations. Deepwater operations are very expensive and often require significant amounts of time between initial exploration and first production. Despite these challenges, operators often reap great rewards. Figure 1 shows the history of discoveries in the deepwater GOM. There was a shift toward deeper water over time, and the number of deepwater discoveries continues at a steady pace.
In addition to the significant number of deepwater discoveries, the flow rates of deepwater wells and the field sizes of deepwater discoveries are often quite large. These factors are critical to the economic success of deepwater development. Figure 2 illustrates the estimated sizes and locations of 127 proved deepwater fields. In addition to their large sizes, the fields have a wide geographic distribution and range in geologic age from Pleistocene through Paleocene.
Fig. 3: Current, potential, and future hub facilities. Credit: BOEMRE Figure 3 illustrates existing and potential hubs for deepwater production. For purposes of this article, deepwater hubs are defined as surface structures that host production from one or more subsea projects. These hubs represent the first location where subsea production comes to the surface, and the hubs are the connection point to the existing pipeline infrastructure. Note that potential hubs are moving into deeper waters, expanding the infrastructure and facilitating additional development in the ultra-deepwater frontier.
Reserves and Production
Reserves and Discoveries
Figure 4 shows the number of deepwater discoveries each year since 1975. Since 1975 there have been at least 285 deepwater discoveries in the GOM, of which 127 have become proved fields, accounting for 11.060 BBOE of proved reserves. In an attempt to capture the impact of the deepwater exploratory successes, in addition to MMS proved reserves, unproved reserves, and resource estimates, Figure 4 also includes publicly-available, industry-announced discoveries (IAD’s). The IAD volumes contain considerable uncertainty, are based on limited drilling, include numerous assumptions, and have not been confirmed by independent MMS analyses. They do, however, illustrate recent activity better than using only MMS-proved reserve numbers.
Fig. 4: Number and volume of deepwater discoveries. Volumes include MMS reserves, MMS resources, and industry announced discoveries. Credit: BOEMRE There is often a significant lag between a successful exploration well and its hydrocarbons being produced. The success of an exploration well may remain concealed from the public for several years until the operator requests a “Determination of Well Producibility” from MMS. A successful MMS determination then “qualifies” the lease as producible and the discovery is placed in a field. The discovery date of that field is then defined as the total depth date of the field’s first well that encountered significant hydrocarbons. Hydrocarbon reserves are still considered unproved until it is clear that the field will go on production. Then the reserves move into MMS’s proved category.
The increase in proved reserves in 1989 is partially a result of the Mars-Ursa discoveries. Likewise, the increase in 1999 is partially a result of the Thunder Horse discovery. These two fields, located in Mississippi Canyon, represent two of the largest in the GOM based on proved barrels of oil equivalent (BOE) reserves. The apparent decline of proved reserve additions in recent years is caused by the lag between discovery and development. The increase of unproved reserves, resources, and IAD’s in 2006 is partially a result of the Kaskida discovery located in Keathley Canyon. In the last 2 years, oil and gas volumes added to the GOM decreased sharply from those in 2006. This is due in part to the fact that MMS has not completed volumetric estimates for 2007 and 2008 discoveries in deep water.
Leasing, drilling, and discoveries all stepped into deeper waters with time. Production, the final piece in the puzzle, is no exception. In 2007, approximately 70 percent of the GOM’s oil production and 36 percent of its natural gas were from wells in 1,000 ft (305 m) of water or greater. Figure 5 illustrates deepwater projects that began production in 2007 and 2008 and those expected to commence production in the next 5 years. Seven deepwater projects went online in 2008: Bass Lite and Neptune in Atwater Valley; and Blind Faith, Mississippi Canyon Block 161, Raton, Thunder Horse, and Valley Forge in Mississippi Canyon. In addition to the projects displayed on Figure 5, more are likely to come online in the next few years but are not shown because operators have not yet announced their plans.
Fig. 5: Deepwater projects that began production in 2007 and 2008 and those expected to begin production by yearend 2013. Credit: BOEMRE The GOM supplied approximately 25 percent of the Nation’s domestic oil and 14 percent of the Nation’s domestic gas production in 2007. A significant portion (approximately 18%) of the oil volume came from the deepwater GOM. Nine projects tied back to the Independence Hub facility came online from July through October of 2007. When at peak capacity, production from the hub will add 1 Bcf/d, representing over 10 percent of the gas production from the total GOM.
Shallow-water oil production rose rapidly in the 1960’s, peaked in 1971, and has undergone cycles of increase and decline since then. Since 1997, the shallow-water GOM oil production has steadily declined and, at the end of 2006, was at its lowest level since 1965. It has, however, begun to increase in 2007. From 1995 through 2003, deepwater oil production experienced a dramatic increase similar to that seen in the shallow-water GOM during the 1960’s, offsetting declines in shallow-water oil production. In fact, beginning in 2000, more oil has been produced from the deepwater areas of the GOM than from shallow waters. Starting in 2003, deepwater oil production basically leveled off. Shallow-water gas production rose sharply throughout the 1960’s and 1970’s, and then remained relatively stable over the next 17 years before declining steadily from 1997 through 2007. At the same time shallow-water gas production started to decline in 1997, deepwater gas production began to increase, helping to offset the declines from shallow water. Gas production from deep water has, however, declined slightly from 2003 through 2007.
Figures 6a and 6b compare maximum historic daily production rates for each lease in the GOM (i.e., the well with the highest historic production rate is shown for each lease). These maps show that many deepwater fields produce at some of the highest rates encountered in the GOM. Figure 6a also shows that maximum oil rates were significantly higher off the southeast Louisiana coast than off the Texas coast. Figure 6b illustrates the high deepwater gas production rates relative to the rest of the GOM. The relatively high gas rates from fields denoted with an asterisk are tied back to the Independence Hub facility. The hub’s 1 Bcf/d capacity accounts for over 10 percent of the total gas production from the GOM. Note also the excellent production rates from the Norphlet trend (off the Alabama coast) and the Corsair trend (off the Texas coast).
Fig 6a: Maximum historic oil well production rates. Credit: BOEMRE
Fig 6b: Maximum historic gas well production rates. Credit: BOEMRE