Virtually every oilfield decision is founded on profitability. With no control of oil and gas prices, and facing steadily rising costs and declining reserves, companies’ basic decisions are based on constantly moving targets. Make no mistake, drilling, completing and producing oil and gas wells is an extremely complex business. One might think that the world’s unslakable thirst for cheap, abundant energy resources makes profitability a sure thing. Perhaps that was true in John D. Rockefeller’s day. But with no control of commodity prices, soaring costs and stiff foreign competition, and with smaller, more elusive reservoirs located in increasingly hard-to-develop places, the U.S. industry has had to turn to technology. Technology is the great enabler that has made exploration more effective, drilling more efficient and production more prolific. At the same time, technology has made drilling and producing oil and gas safer and far less intrusive to the environment. Oil-rich OPEC held the rest of the world hostage in the 1970s with its infamous oil embargo, driving prices up, but it does not control the market as tightly any more. In today’s environment, companies develop business strategies for several different price scenarios, taking into account the cost of capital and regulatory compliance. Then they go about attempting to control the two things they can influence—their exploration success, and their drilling and production costs. This is where technology comes in. To use an analogy, the development and use of oilfield technology closely parallels the conquest of space. From the early days of the Wright brothers, the technology of flight has increased exponentially. The same is true for exploration and production of oil and gas. For example, until the 1980s only one in 10 exploratory wells—called wildcats—were successful—that is, they found economically recoverable amounts of hydrocarbons. Today, thanks to improved technology, about 25% to 40% of rank wildcats are successful, and in some states, the success ratio for development wells is much higher. Development wells are those drilled after exploratory wells have indicated hydrocarbons. It is often from development wells that oil and gas are produced. In the Appalachian Basin, many companies report drilling success ratios of 80% or 90% when drilling development wells to develop a field after the initial wildcat “comes in.” Often discovery wells prove to be in locations that prove to be sub-optimal for efficient production of the reservoir, so several development wells are drilled to fully exploit the discovery. The original discovery well may be deemed unsuitable for production and will be plugged. Since the beginning of the new millennium, commodity prices have soared and held steady at unprecedented levels. Prices reflect strong increases in global demand as well as threats to supplies. Threats are natural, like hurricanes that can shut down offshore production, or political, like the crisis in the Middle East, or the actions of unstable governments. Costs have risen as well, because the new technology required to drill and produce from increasingly difficult areas is not cheap. Companies are now pursuing the prize in waters as deep as 10,000 feet (3,300 meters) and are going after unconventional gas resources, in tight gas reservoirs, in shales and in buried coal seams. A new potential gas resource is being explored called methane hydrate. Methane hydrates consist of hydrates that are unstable frozen clusters consisting of a molecule of methane, completely surrounded by several molecules of frozen water. They exist in great quantities all over the world in a natural stable state only under specific conditions of pressure and temperature. If they are removed from their stable environment, they thaw and the methane escapes to the atmosphere. Researchers around the world are aggressively pursuing the development of enabling technology that will permit safe, commercial recovery of methane gas from hydrate deposits. So far, they have resisted all efforts by companies eager to develop them for commercial purposes. Costs of technology to solve this production problem will be steep. Upon developing a prospect, there are several cost-risk points at which a company must decide whether to continue: Is the prospect worth drilling? And after a discovery well is drilled, are the initial, visual results worthy of obtaining more sophisticated test results? If, yes, then, do these results indicate the prospect is worth completing and bringing into production? In every case, the decision to proceed must be weighed against the cost of the added work that must be done as well as economic factors dictated by access to transportation (pipeline, river, road or railroad) to a refinery or consumer concentrations.
DRILLING THE WELL
With a few notable exceptions, the basic technique of drilling a well has not changed much. Based on data from surface exploration techniques such as 2-D and 3-D seismic, geologists and geophysicists decide on suitable acreage for drilling. Companies then secure a lease from the landowner, or from the appropriate authority in the case of federal or state land or offshore leases. They contract a drilling rig. Contrary to popular opinion, oil companies do not have their own rigs, relying instead on an experienced cadre of drilling contractors who supply the equipment and workers to drill the well for a specific day rate. Modern rigs have banks of diesel-driven generators to provide the electrical power that lights the rig and drives the drill. The drilling function can be simplified by grouping it into two systems: the hoisting/rotating system and the circulating system. The former consists of the familiar derrick with its bright yellow block and cable hoist that trips the drill pipe into and out of the hole and supports its massive weight during drilling. Rotating is accomplished by a rotary drive traditionally located on the drill floor, but more recently located atop the drill string—the so-called top drive. Top drives are a perfect example of how technology has improved safety and efficiency by reducing the number of times— by a factor of three—the drilling activity must pause to add a joint of pipe. The circulating system pumps heavy drilling fluid down the drill pipe to cool and lubricate the bit, float rock cuttings to the surface, and control well pressures. Drilling fluid—commonly called mud—is really a high-tech formula containing chemicals that interact with the rock formations to ease drilling and protect the borehole wall. The high pressure imposed by the heavy column of mud balances formation pressures, and prevents the influx of well fluids or gas into the borehole. This prevents the catastrophe known as a blow-out and is usually sufficient, but for added safety, each rig has a stack of valves just beneath the drill floor or on the seabed called blow-out preventers (BOPs) that can be closed to seal the well in an emergency. Drilling mud containing rock cuttings circulates up the outside of the drill pipe to the surface where it is filtered, de-gassed and recalculated.
REDUCING DRILLING COSTS
The most notable applications of technology to reduce drilling costs have been in the areas of automated pipe-handling, improved drilling rates and geosteering, whereby real-time geological data are used to steer the bit into the target reservoir and keep it there. As much as 40% of non-drilling time is spent handling pipe. Now computer-driven machines are taking over this time-consuming and dangerous job. Drilling rates are facilitated by new bit designs and by the use of underbalanced drilling, whereby the well is allowed to flow under controlled conditions while it is being drilled. New instrumented bits allow dozens of critical measurements of formation and drilling parameters to be acquired and transmitted in real time to the surface. This improves drilling efficiency and accuracy. Finally, years of painstaking research have yielded environmentally friendly drilling and completion fluids as well as closed circulation systems, and most offshore locations follow a zero-discharge policy, meaning absolutely no well or rig effluent is put into the sea. Some things never change, however. Drilling is still a demanding, 24-hour-a-day job that must be accomplished safely and efficiently in all kinds of weather in some of the world’s most inhospitable locations.
TESTING THE WELL
Since the beginning, oil companies have tried to evaluate their wells to answer these basic questions: Is there oil or gas? How much? Can it be produced technically, and economically? How fast? For how long? Should we complete this well, or abandon it now before spending any additional time and money? Where should the next well be drilled? The answers to these questions are fundamental to every economic decision that must be made over the life of the well or reservoir. Formation evaluation technology has kept pace with drilling technology with new sophisticated well logs, cores and well tests. Periodically during drilling, the drill pipe and bit are removed, i.e., “tripped” out of the hole, so electronic instruments can be introduced into the well on an electrical cable called a wireline. The measurements made by these instruments are plotted on a chart called a log. Alternatively, some logging data can be acquired while drilling, as noted earlier. Logs are used to determine the location and thickness of hydrocarbon-bearing strata and indicate their orientation in geospace. Cores, once the only sure way to determine formation mineralogy and physical characteristics, are formation samples cut and recovered from the rock. Cores are now being challenged by sophisticated high-resolution nuclear spectroscopy log images to accurately describe formation texture, porosity and permeability. Well tests help determine reservoir volumetrics as well as pressure and flow rate of the well once it is placed on production. Information is the key. Now computer databases are constructed from the outset, increasing reservoir knowledge with compatibly scaled data as each measurement is taken. This knowledge base facilitates decision-making and reduces risk. Virtually every decision is prefaced by a cost-benefit analysis that projects its economic effect. Today, sophisticated computer reservoir models can be integrated with dynamic surface-production-system models to simulate the entire production system from pore to export pipe. Real-time downhole test data can be transmitted via satellite from the field back to a company’s headquarters—even in another country—so that scientists, engineers and managers at home base can evaluate the well and make the proper decisions.
COMPLETING THE WELL
As the well reaches its completion phase, decisions become easier because discounted cash flow models can be used to compare the incremental benefit of each expenditure with the out of-pocket cost. The immediate effect of technology improvements can be felt as the well is cased and casing is cemented in place to achieve hydraulic isolation of producing formations. New expandable casing technology has been developed to reduce the cost of casing the well and improved cements provide a higher margin of safety atless cost. New, deep-penetrating perforating guns fire explosive charges downhole, piercing the casing of the wellbore, the cement and the rock itself to provide flow paths for the hydrocarbons to enter the well and flow to the surface. Finally, a string of production tubing and a packer is run downhole to provide a high-pressure conduit for production and the well is topped by a system of valves called a “Christmas Tree.” Often the drilling rig is released once casing is set, and completion is accomplished with a smaller, less expensive unit. “Intelligent wells” are increasing in popularity. These contain permanent monitoring sensors that measure pressure, temperature and flow and telemeter these data to surface. More importantly, these wells contain surface-adjustable downhole flow-control devices, so, based on the dynamic production information from all the wells in the reservoir, flow rates can be optimized without having to perform a costly intervention. Wells that do not have sufficient natural formation pressure are produced by new high-tech electrical submersible pumps. These contain sensors that measure pump performance and efficiency, and telemeter the information to the production-operations center. The most significant result of these improvements is optimized production rates and extended reservoir life.
Regardless of the quantity of hydrocarbons present, oil and gas wells do not always behave as we would wish them to. Some require extensive, and expensive, treatments before they will produce economically. Sometimes the subsurface formation must be washed with acid to clean out clay or other materials that are clogging the pores and impairing flow. In formations with low permeability such as limestones, hydraulic fracturing is used to crack the rock and create a greater area of flow between the wellbore and formation pores. Conversely, in unconsolidated sandstones, screens must be placed within the well to keep sand from flowing into the well bore, clogging it and eroding the tubulars. Each treatment can be accurately costed, and justified in advance, using cash flow modeling based on incremental added production. Where natural reservoir pressure is lacking, wells will not flow to the surface and must be assisted by pumps or artificial-lift systems. Lifting costs can be considerable, and must be considered along with finding and development costs, which are those expended to this point. In the United States, average lifting costs are about equal to average finding/development costs, making many wells uneconomic. Complicating things is unwanted water production. More often than not, water is co-produced along with the oil or gas. Not only does each barrel of water produced mean one less barrel of oil, but the water must be safely disposed—it is usually salty and of no value for drinking or irrigation. Typically the water is pumped into a injection well, or it is trucked away from the surface location, to be safely disposed elsewhere, according to local or state regulations. New technology allows oil and water to be separated downhole and the unwanted water is reinjected into a nearby nonproductive formation—never reaching the surface.
Throughout the life of the individual well and reservoir, periodic interventions are made to acquire production data and perform overhauls, called workovers. Slim logging tools can pass through the production tubing and make flow measurements. The result of this allows remedial steps to be taken to optimize flow. As long as they can be economically justified, elaborate enhanced-production schemes can be launched to improve the ultimate recovery factor—total percentage of recoverable oil from the well—which can reach as much as 70% in some cases. Enhanced oil-recovery (EOR) methods include water-flooding, where water is pumped into injection wells drilled around the flanks of the reservoir, forcing more oil out the central, producing well. Other EOR techniques include steam-flooding or CO2 (carbon dioxide) injection that melt or dissolve viscous oil deposits and improve their flow characteristics. Even more exotic methods involve fire- flooding, in which a downhole fire is started to melt heavy oil, or the injection of microbes that eat the polymers that are binding the oil in place. Each of these schemes undergoes a cost/benefit analysis before attempted. Even under the best of scenarios, a well may only produce 10% to 20% of the oil in place in its lifetime, absent stimulation.
Offshore, costs dictate that entire fields be produced from as few facilities as possible. This is especially true in deep waters or in harsh environments such as the North Sea. Tall jacket platforms sit on the ocean floor and serve as production facilities for 20 or more wells. The wells all come together at the surface, but branch out in all directions underground to tap the farthest reaches of the reservoir. In harsh environments, huge gravity-base structures combine the roles of supporting the production facilities and serving as storage tanks for the crude oil. Recently, tension-leg platforms and spars have been introduced. These are floating platforms tethered to the ocean floor, but free to move about with wind and current. They can often be economically re- located and re-used for other fields when the original field is depleted. With deepwater discoveries, an entirely new technology has made production economical. Floating production, storage and offloading (FPSO) vessels are converted oil tankers with production and processing equipment on deck. These receive oil from flexible risers connected to gathering stations and subsea wellheads located on the sea floor. They process the crude and store it until offloaded by a shuttle tanker. In highly developed areas such as the Gulf of Mexico, FPSOs may not be as economical as running a subsea pipeline several miles from the wellhead to connect to a fixed platform in shallower waters. Subsea connectors as long as 100 miles are in use today in the Gulf of Mexico.
In the United States, producers face stiff challenges. More than half of the country’s oil now comes from “stripper” wells, which produce 10 barrels of oil per day or less. If oil fetches $11 or $12 per barrel at the wellhead as it did in the late 1990s, then most of these wells are uneconomical, once finding and lifting costs and taxes are factored in. However, if a well is abandoned, it might never be brought back on production. So, oil companies— most of them small independent operators— are faced with a real dilemma. They can try to hang on and hope for higher prices, they can invest in expensive cost-cutting schemes with little hope of a quick recovery, or they can shut-in their wells. Even with today’s high prices, it’s a gamble. No one knows how long high prices will last. Should the well’s owner invest millions to try to improve a poor producer? Will the owner be able to recoup the investment before the next down-cycle? Compounding the problem is the intensification of natural decline rates from existing wells. Over time, whether it takes four years or 30 years, every well will produce less and less until it is no longer economically viable. U.S. reserves are being depleted faster than ever before. More discoveries are needed and more technology is required to improve existing productivity. Americans are going to be asked in the not-too-distant future if they are willing to accept importing as much as 75% of their oil from sources abroad. What national security and economic risks does this imply?
(Source: Excerpt from E&P: An Investor’s Guide—Dick Ghiselin)