September 2008 ///
Dual over/under configurations extend lower frequencies and help image through basalt and salt, as well as improving steep dip imaging. Triple over/under acquisition further improves data quality, especially in rough sea conditions.
Explorationists are constantly searching for data and tools to evaluate and reduce drilling risk. Drilling a non-producing well is generally costlier than evaluating all possible risk based on the available data before drilling. Hence, in the initial phase of the operation, gathering data to determine if the drilling target will prove worthwhile is critical.
This article presents a post-stack analysis of seismic data from a field with 15 producing wells in a standard federal lease in the Gulf of Mexico. The analysis includes the following attributes: amplitude, spectral decomposition, dip of maximum similarity and instantaneous Q, in addition to well log information. The objective is to provide an overview of best practices to determine the pay signature within the seismic dataset, reduce the inter-well stratigraphic interpretation risk, define anomalies by understanding their fundamental cause and reduce structural trapping risk.
Wide-AZimuth (WAZ) marine streamer survey designs are aimed at increasing the crossline offset and azimuth distributions in marine streamer surveys to better image complex geologies and the sub-salt. Since there is a limited amount of crossline offset that can be achieved with a conventional narrow-azimuth towed streamer spread, most WAZ survey designs have aimed at decoupling sources and receivers, placing the sources laterally from the receiver spread to achieve the additional offset.
Successive passes down the same source lines are then required to extend the offsets. This leads to the familiar concept of a 4D acquisition, where the primary (and most realistic) goal is to achieve a repeat position of the Center Of Source (COS). As WAZ-type acquisitions can require multiple sail-line passes to achieve the required crossline offset, and most require a shot regularization to a fixed grid, it becomes increasingly important to minimize errors in source positioning.
The high rewards of finding hydrocarbon in subsalt plays make them very attractive for exploration. However, it is a challenging mission. Subsurface pressure uncertainty causes recurrent failure to reach the drilling targets.
After the discovery of Mahogany Field in the GOM 15 years ago, special attention was directed to subsalt plays. That attention gradually shifted from the shelf to deep water (>1000-ft water depth), Fig. 1. Deepwater yearly production increased from 21 million bbl of oil and 33 Bcfg in 1985 to 339 million bbl of oil and 1.1 Tcfg in 2006, according to the US Minerals Management Service. Consequently, the cost of acquiring and testing prospects has increased due to the prospects’ location in deepwater salt mini-basins. The prospect’s risk results from intricate geopressure compartmentalization in a salt environment accompanied by a deep mud line, deep target depth and shallow sediment hazards.
A novel tool designed to detect and react to drillbit vibration was tested at the Rocky Mountain Oilfield Testing Center (RMOTC), located in Teapot Dome Oil Field, also known as Naval Petroleum Reserve No. 3 (NPR-3), near Casper, Wyoming. This new tool, the Active Vibration Damper (AVD), developed by APS Technology, Inc., monitors vibrations in the BHA and adjusts the damping coefficient to reduce them. This was the first field test of the device, which had previously been tested at a drilling laboratory.
The AVD was developed under contract with the US Department of Energy Deep Trek Program. Smith Services is the commercial partner and collaborator in the testing and potential commercialization of the tool. Smith and APS partnered with RMOTC to conduct a test of the AVD in a field with an extensive drilling history for comparison.
The RMOTC tests showed the AVD improves drilling economics in two areas: It increases ROP while minimizing vibration.
The US Gulf Coast contains the largest known deposits of salt in the world, Fig. 1.1 Almost 60% of these salt zones remain unexplored. The areas that have been explored in the Gulf of Mexico range from the Ewing Banks area to the Mississippi Canyon area, Fig. 2.2 There are also more than 400 underground salt storage caverns in 27 states and Canada with a capacity to hold over 3 Tcf of gas, Figs. 3 and 4.3,4 The importance of these salt structures and the potential they represent to future oil production and gas storage have become very significant with declining oil reserves. An article describing sub-salt exploration in the GOM explains the industry attention focused on sub-salt formations: “For 45 years, exploration and development drilling in the Gulf of Mexico stopped when salt was encountered at objective depths.
The reasons for wireless are clear: Broad range of applications can deliver compelling benefits, and open-standard approaches are expanding supplier participation and the range of functionality available to end users. Various sources estimate the demand for wireless technology in industrial process automation to exceed $1 billion by 2012 or earlier. Following more than three years of field trials, Emerson Process Management began shipment of its SMART Wireless products for automation monitoring and control applications in late 2006.
SMART WIRELESS NETWORKS
The self-organizing field network technology delivers data at greater than 99% network reliability, and installed costs are much lower than a wired equivalent. Field network solutions combine gateways with wireless-enabled transmitters and predictive maintenance software, all seamlessly integrated with automation systems or with legacy hosts. Remote Operations Controllers extend the self-organizing wireless networks for use in remote production and distribution facilities.
Williams Production RMT is one of the most active operators in the Piceance Basin near Parachute in northwest Colorado, operating about 25 rigs in the region. The operator produces more than 560 MMcfd of natural gas from more than 2,300 wells. Many of the rigs that the operator uses in the Piceance Basin are set on a drilling pad that can contain up to 22 directional-drilling well slots, typically about 7,000-9,500 ft total depth. The wells usually reach TD in 10-12 days, drilling the top 2,000 ft or so with a 13½-in. roller-cone bit and a 13½-in. PDC bit, then finishing the well with several five-blade 7 7/8-in. PDC bits. In some wells, the operator was using as many as three to four 5-blade bits to complete the 7 7/8-in. interval due to the various formations encountered.
Valhall Field, operated by BP Norge AS in the North Sea, is undergoing a massive redevelopment that will allow the field to keep producing until about 2050. In total, more than $2.3 billion is expected to be invested in upgrading the field. The operator is investigating strategies to protect the field against damage associated with waterflood and to minimize costs in its next phase of production.
The reservoir management plan for the Valhall redevelopment relies on multi-zone water injection and management of offset water in producing wells. It was recognized that cementing the reservoir liner could prevent isolation between the injection points or make the pre-perforated sliding sleeves inoperable, due to cement fallout.
Swellable packers were identified as a potential solution for zonal isolation that would limit the risk of damaging the perforation valves and reduce operational risk when running and cementing the reservoir liner.
Cantarell Field is the most important complex in Mexico and is the second-largest producing field in the world. Matrix acidizing has always been the main stimulation process used to improve production from the carbonate reservoirs that form the main productive zones, and this is especially the case now that this mature complex has reached its production peak.
A critical factor for success of the treatments is distribution of the acid among all productive zones. Since most producing wells are not homogeneous and contain layers of varying permeability, even distribution of the acid is a difficult task. In addition, the water saturation of the various zones has a major effect on the acid distribution. Since acid is an aqueous fluid, it will tend to predominantly enter the zones with the highest water saturation, in many cases resulting in increased water production. This brings with it the multitude of problems associated with high water production.
High production and low risk were achieved by encouraging sand production.
Increasing oil and gas production is a key business driver. As a result, companies are spending more time optimizing what they have already found. BP has achieved good results using sustainable best practices and process optimization solutions.
The Azeri oil and gas production asset is within the top five BP investments worldwide and is possibly one of the world’s most complex oil systems. Present offshore facilities consist of three production platforms and a gas processing platform, located in the Caspian Sea. Each production platform has oil/water separation, gas compression and gas dehydration. The gas processing platform has four parallel compression trains driven by 25-MW gas turbines, which supply high-pressure gas for reservoir pressure maintenance and gas lift for oil production. The onshore terminal has four oil-stabilization trains, oil and gas receiving facilities and a gas plant for quality control.
The commonsense effect of high oil prices is reflected in the numbers in these tables. But remember, this is during 2006−2007, when prices were high (~$60−$80), but not the lofty, well-over-$100 prices of this year.
Reserves should have increased in 2005−2007, even if only due to higher prices. Generally speaking, the higher the price, the more that can be spent increasing recovery. However, it is interesting just how little effect high prices have had on “official” proved reserves. Some have not changed for years. There are several reasons for this.
One is that, unless the company is publicly traded like the IOCs, there is little need to spend the time it takes to continually audit the replacement of reserves. In addition to a lack of need, in most cases, NOCs simply do not have the dynamic computer models and personnel needed to do the job.
In general, downhole control lines are not subject to routine failures, but a study of downhole completion failures identified them as a principal failure cause. The cost of recovering downhole completions to repair control line failures warranted the investigation of equipment reliability including control lines, clamps and fittings.
Early work indicated that the components were not engineered as a system, but rather as individual components driven by the hardware interfaces of more substantial components at the physical limits of the system. Hence, the mechanical attributes of the components collection had never been closely studied. To fill this knowledge gap, a system-level approach was developed to understand and resolve the problem areas. This article details that process.
An integrated team of completions and subsea engineers found that the control line and its components may not be engineered to the same rigor as the rest of the subsea and completion system.
In recent years, deepwater exploration has had to face a fresh set of challenges that are very different from the hurdles that faced deepwater pioneers in the 1990s. Many of these challenges have been driven by the sharp rise in oil prices in this period, and in this article we look at full-cycle returns in key deepwater basins under a $100/bbl long-term Brent oil price assumption.
The chart shows a comparison of deepwater volumes discovered and the full-cycle economic returns generated by these discoveries. The bubble sizes are based on the relative exploration spend in each basin.
Under this price outlook, deepwater returns average around 20%-sufficient to keep deepwater exploration attractive despite the well-documented increases in drilling costs over the period. The highest returns have been in basins with very localized discoveries. In Ghana, Jubilee Field is still being appraised, but in the Baram Delta the Kikeh development came onstream quickly and cheaply.
Increasing fuel price in the US and other countries has been the hot button topic for the last several months. Emotions have been inflamed by continued reports of folks having to forego driving to buy food, pay utility bills and purchase prescription medications. Everyone has an opinion, with most of them being negative toward “Big Oil,” even though the crude price increase has been experienced by all oil companies, big, small and national.
Interestingly, through all the investigations and grilling of Big Oil executives, there has been no evidence of collusion, price fixing or price gouging. The phenomenon has been caused by a perceived supply gap (surprise!). High prices caused a demand drop and a subsequent crude oil price drop (another surprise). Perhaps this free market stuff really works!
Fueling the controversy (no pun intended) is that retail prices increase faster along with rising crude prices than they fall with declining crude price.
Unfortunately, when it comes to energy policy, it takes political panic to get anything done. Everything about President Bush’s energy policy was correct as far as direction goes, but providing a secure and plentiful energy future just wasn’t important enough to be funded seriously. The past and present Congresses have mirrored Bush’s approach with a series of “near misses.” “Clean coal” is one near miss. Strictly speaking, it should be called “cleaner coal.” Nevertheless, given coal’s abundance, clean coal is a goal worth pursuing, especially since most of the required technologies are already known-it’s just a matter of integrating and perfecting. After funding and hyping the so-called “FutureGen” coal plant of the future, the US Department of Energy is now ending that funding, after spending millions, because of cost overruns. In typical governmental wisdom, if future technologies incur cost overruns, they aren’t worth developing.
Canadian Superior Energy made a natural gas discovery with its Bounty well in Block 5(c), 60-mi offshore Trinidad. The well tested 60 MMcfd from 200 ft of pay with possible reserves of 2.6 Tcf. The well drilled to a 17,360-ft TD. Canadian Superior is operator with a 45% interest in the block and has partners BG (30%) and Challenger Energy (25%). Petrobras has made another light oil (30°API) discovery in Block BM-S-11 in the Santos Basin of Brazil. The 1-BRSA-618-RJS (1-RJS-656) was drilled on the same block as the company’s Tupi discovery, but on a separate structure. The well is in 7,316 ft of water about 143 mi offshore Sao Paolo state. The pre-salt, lower Cretaceous reservoir was encountered at 18,374 ft. Petrobras (operator, 65% interest) has partners BG (25%) and Galp Energia (10%).
Europe. BG Norge confirmed its earlier Jordbaer discovery in Block 34/3, PL373S of the North Sea Norwegian sector, with its 34/3-1S well.
The dazzling 2,008-drum opening ceremony at the Olympic Games in Beijing was mind-boggling to behold. The precise, immense display of discipline and harmony starkly contrasts with muffled reports of horrendous human rights violations and press and Internet censorship.
Absent also is any discussion of China’s mercantile export policy, which floods world markets with cheap goods produced by workers earning sub-par wages, and is breaking the back of manufacturing sectors in several countries.
Despite these offenses, many self-declared diehard anti-Communists salivate at the prospect of doing business with such an enormous market. At the same time, a little Communist island nation with an economy in shambles inspires fear and hatred from many businessmen, despite the massive wads of petro-dollars that could be made by doing business with Cuba.
Why doesn’t the US government forget about animosities and open a way to negotiate with Cuba as it did back in 1972 with China? ask many analysts.
The Haynesville Shale is the hottest play in North America, and Chesapeake Energy Corp. leads in leasing and drilling. Chesapeake believes there are 250 Tcfe of Estimated Ultimately Recoverable (EUR) resources in an area covering 3.5 million acres in northern Louisiana and East Texas. The company’s share may be as much as 44 Tcfe. CEO Aubrey McClendon said in July that the Haynesville play is likely to become the largest gas field in the US, and the fourth largest in the world.
I am skeptical about this resource prediction. It exceeds the proved gas reserves of the US (215 Tcfe) by 16%, and is nearly 10 times the size of the largest gas field in North America (Prudhoe Bay, 26 Tcfg). It is more than nine times the US Geological Survey’s estimate for undiscovered Barnett Shale reserves (26.2 Tcfe).
The consortium developing the enormous Kashagan Field got a brief reprieve last month when the Kazakh government agreed to move the deadline for first production to 2013—the fourth delay since oil was struck there in 2000.
The government had originally rejected the new development plan presented in June 2008—which also projected a huge total cost of $136 billion to reach first oil, up from $57 billion originally predicted—but reconsidered after securing a number of concessions from the oil companies. The new agreement, which will be finalized this month, highlights the many technical challenges that have turned the world’s largest discovery of the last three decades into one of the most difficult engineering problems in history.
Even in the exploration stage, the consortium formed in 1997 to develop the northern Caspian Sea faced hurdles. Shell led the effort back then, with partners Statoil, Mobil, Total, Britain’s BP and BG, and Eni subsidiary Agip.
News & Resources
InterMoor Inc., along with Murphy Sabah Oil Co. and Petronas Carigali, has installed the world’s deepest conventional mooring system. The semisubmersible rig Ocean Rover, working on the Buntal exploration well offshore Sabah, East Malaysia, was moored at depths that required two of the anchors to be set in more than 8,000 ft of water. The deepest leg of the eight-leg conventional mooring system reached 8,431 ft. InterMoor provided mooring analysis, installation procedures and installation supervision on the project. Each mooring leg, deployed using the anchor-handling vessels Normand Ivan and Normand Atlantic, consisted of a 10-metric-ton Stevpris anchor with the rig’s self-contained wire and chain.
Fugro has created Fugro Gravity & Magnetic Services (FGMS) to market its gravity and magnetic capabilities for oil and gas exploration and production. The unit is the business development arm of Fugro Airborne Surveys, Fugro Ground Geophysics and Fugro Robertson (marine).
In July, global oil supply increased by 890,000 bpd to 87.42 million bpd. Canada and Norway led the way with 300,000-bpd and 150,000-bpd increases respectively. July OPEC crude production increased by 370,000 bpd due to increases in Saudi Arabia, Iran and Nigeria, though about 500,000 bpd of production remains shut in in the latter. IEA estimates that effective OPEC spare capacity is 1.5 million bpd, but should rise in 2009.
By early August, crude prices had fallen $30 per bbl from mid-July highs on weaker OECD demand and increased supplies, and because the first US Gulf hurricanes passed without causing damage.
The international and US rotary rig counts continue to remain high at 1,596 and 1,932, respectively, for July 2008, showing increases of 148 and 155, respectively, over the 2007 numbers.
Long-life high-pressure pumps
FMC Technologies’ 2400-hp Triplex and 2700-hp Quintuplex Well Service Pump models are high-pressure pumps capable of delivering flowrates up to 50 bbl/min. at pressures up to 20,000 psi. Both models are designed with 250,000-lb rod load. The pumps have been successfully tested 1 million total test cycles at full rod load, a testing procedure that no other pump manufacturer has completed before. Design improvements, developed with the help of key fluid control customers during the initial phases of the project, allow end users to operate the pumps at slower speeds than competitive models. As a result, they generate significantly less wear on critical components, extending service life and reducing total life-cycle cost.
Subsea remote intervention torque tool
Mako DeepWater, a Houston-based subsea remote intervention service, has introduced the Tiger Shark torque tool. Recognizing that about 50% of all current industry field personnel have less than five years of experience, the tool was developed with a focus on simplicity and reliability.
Industrial technology specialist Tracerco, part of the Johnson Matthey Group, has appointed Vince Croud as Technical Director. He will oversee the company’s R&D activities at its Tracer Technology Centre in Billingham, England. Croud has published 27 scientific papers and secured 21 patents for his own inventions.
Key Energy Services Inc. announced that Kimberly R. Frye has been promoted to Senior VP and General Counsel. Frye joined the company in October 2002 and has served as its Associate General Counsel.
Enventure Global Technology announced the appointment of Greg Bailey as VP of Engineering and Technology. With more than 20 years of engineering experience, he will lead the company’s engineering and R&D divisions. Prior to joining Enventure, Bailey worked for Grant Prideco, where he served as VP of Engineering in the tubular technical division.
In late July, the Bulgarian Parliament ratified an agreement between Bulgaria and Russia on the building of the South Stream pipeline. Bulgaria’s interests are fully defended because the company that will develop and operate the pipeline on its territory will be with 50% participating interest of Bulgaria and 50% participating interest of Russia. South Stream will transport Russian natural gas to Italy. The pipeline is to extend under the Black Sea, from Russia’s southern port of Novorossiysk to Bulgaria, and then onward to Austria and Italy. Russia’s Energy Ministry recently announced a preliminary cost assessment of the project at $20 billion, up from the initial assessment of about $10 billion.
Repairs to Shell’s damaged oil pipeline in Nigeria have been slow, a Shell spokesman said. Shell’s Nembe Creek line, located in the Niger Delta, was sabotaged in late July, and repairs have been struggling to make significant progress.