Operators squeeze harder

Naturally, most operators want to explore to find new sources of energy, or at the very least, replace the reserves they have produced. But with apologies to the explorationists, 2010 seems to be the year of production. Squeezing the last commercial drop of hydrocarbon out of the rock has become the goal of many. Not to ignore the scientific breakthroughs that have benefited the search for additional reserves, but there always is a certain element of luck attached to a discovery. Not so with production. Production improvements are the result of the diligent application of science, technology, and perseverance, and lots of it.

In many cases, the industry has tackled the new frontiers of unconventional oil and gas. Commercial wells are being made today in areas that were unimaginable a few short years ago. For example, how many people would have ever believed that the industry could coax gas from rocks whose permeability is measured in nanodarcies?

Operators are increasingly wringing low-gravity crude from heavy oil reservoirs using cutting-edge technology to find it, discriminate it from freshwater, and produce it cost-effectively.

Persistence is paying off in Canada’s famous tar sands, where recovery techniques have allowed operators to pass the breakeven point thanks to new production techniques.

Cleanwave Water Treatment Service modular units deliver high volumes of treated water for formation stimulation. (Illustration courtesy of Halliburton)

The industry is enabling new channels to market by solving the transportation issues that previously made it uneconomical to move energy from production facilities to thirsty industrial and population centers. As a result, areas that had abundant energy resources but no consumer infrastructure now can generate positive cash flow from their natural resources.

In the conventional oil and gas arena, new deep- and ultra-deepwater fields are coming online largely thanks to production and construction technology. Traditional deepwater hot spots such as offshore Brazil and the Gulf of Mexico (GoM) are being joined by new discoveries in India’s Krishna-Godavari Basin in the Bay of Bengal. Huge natural gas discoveries in the deepwater eastern Mediterranean are changing the game for the Middle East and Asia Minor.

The technology of extended-reach drilling (ERD) has made a number of prolific fields accessible for production. In the Arctic regions of Russia’s Sakhalin Island and offshore Alaska, tapping resources under treacherous sea ice has been enabled through ERD. World record-length wells have become commonplace in these areas, where both the drilling rig and subsequent production facilities can be located on dry land while producing wells eight miles (13 km) away under the ice. Even in the warmer waters offshore Qatar, ERD wells drilled from a central location enable the operator to tap vast resources from a very small footprint, thus minimizing the environmental impact.

These days, entire subsea fields are being produced from a few optimally placed wells that feed a central floating production facility. New deepwater fields such as Shell’s Parque das Conchas offshore Brazil and Perdido in the GoM provide innovative examples of applied new technology. Dozens of firsts were recorded in drilling, completing, and producing these fields. After decades of delay, the authorities have given Petrobras the honor of being first to break the logjam of installing a floating production, storage, and offloading vessel in the GoM.

‘Houston, we have a problem’
Can anything stop the worldwide campaign to boost production from existing reservoirs? Unfortunately, the answer is, “Yes.” Both external and internal threats can have dramatic implications on industry goals. The external issues are well-

Sophisticated logs and radioactive tracers give Bakken consortium operators valuable clues to optimize future frac designs. (Logs courtesy of Schlumberger)

known and have been around for years. Commodity prices play a huge role in cost versus value decisions that determine the economic viability of a proposed initiative. Following the stratospheric peak of US $140 oil where almost anything was justified, the markets tanked for a short period in the $30 range. Prices have firmed somewhat and now are more stable in the $80s, a number that OPEC says is reasonable. In addition, politics cannot be overlooked as an external impediment. For years, operators have bemoaned the lack of access to federal lands in the US where natural gas has been discovered, and thanks to the political reaction to the Macondo incident, it is likely that offshore permits will be more difficult to get. The prolific GoM permitting is threatened, and forget about offshore Atlantic or Pacific prospects. Countless new regulations will provide high hurdles for the industry to climb. But these impediments have been around in one form or another for many years.

A more insidious problem is that of knowledge gaps. An internal issue, the need for detailed foreknowledge, has been identified as essential for success in reservoir development. Operators who proceed to implement drilling and completion programs without essential knowledge about the formations, the reservoir, regional geomechanics, and geochemistry risk suboptimal results. Hundreds of papers have documented cases where prior understanding of formation anisotropy, stress fields, and detailed mineralogy have enabled successful wells to be steered and completed in reservoir sweet spots.

Often the industry is its own worst enemy. Drilling departments have been reluctant to authorize the gathering of information from logs or cores unless the data has direct relevance to the well-construction process. Information that could prove invaluable to a production department often is scrubbed in the interest of cost control. Countless papers have been written that show how completion designs and stimulation programs are optimized when certain formation parameters are known in advance. This is particularly true in shale gas development.

Recently, water, or the lack of it, has loomed as a major issue affecting hydraulic fracturing practices. Proppant shortages also threaten the efficient implementation of completions. The former issue has spurred a spate of solutions, from recycling of frac water to the use of produced water from specifically drilled brine wells.

One of the most promising is Halliburton’s Cleanwave Water Treatment modular system. Each module can produce 20 bbl/min of treated water, and when more volume is needed, additional modules can be deployed. On the latter issue, proppant companies are scrambling to find new quarries and mills to meet demand. Technology has played a role in helping companies maximize fracturing performance, but shortages of critical elements and equipment continue to impede progress.

Production enhancement programs are rife
Innovative minds are at work developing new tools and techniques to improve production. These range from new ways

The “zipper frac” technique helps operators optimize treatment effectiveness on adjacent wells in Oklahoma’s Arkoma Basin. (Image courtesy of Schlumberger)

to perform massive multistage stimulation jobs to small embellishments in mature processes. In the Bakken play of North Dakota, an industry consortium of seven operators drilled three horizontal lateral test wells on a production-sharing basis for the express purpose of establishing best practices for use on subsequent wells. With the help of four non-participating service company partners, they tried a number of new drilling and completion techniques to find the combination that consistently delivers the best results.

The group evaluated lateral placement, prediction of fracture intensity and orientation, sweet spot prediction, optimized stimulation design, the benefits of real-time fracture mapping, and the feasibility of reservoir extension. The work drew a clear correlation between perforation placement and fracture performance. Secondly, a close correlation between frac fluid viscosity and fracture spacing was observed. Finally, (for the Middle Bakken, at least) a correlation between cross-linked frac fluid and fracture height growth was observed that was not present when slickwater techniques were used.

One clear conclusion of this work was that the more foreknowledge available at the time the completion is designed, the more likely the completion is to perform to expectations.

The recent Society of Petroleum Engineers Annual Technical Conference and Exhibition in Florence, Italy, offered several examples of easy-to-implement, economical techniques to optimize production. In mature reservoirs producing with high water cuts, it is difficult to identify from where production is coming. Many wells in these depleted fields are produced using electrical submersible pumps (ESPs); therefore, running production logging tools to evaluate production can be costly and problematic. A novel idea was presented where a fiber-optic distributed temperature monitor was run below the ESP. The temperature profile log could not identify the zones producing oil but could easily identify those zones producing water from nearby injector wells. By systematically turning injectors on and off, it was easy to see which injectors were contributing to which zones. On a subsequent workover, the water zones were squeezed off or isolated using a casing patch, significantly increasing the oil recovery fraction from the producing well. The distributed temperature monitor was recovered and moved to another problem well in the field, deployed with the pump, and the process was repeated.

Hydraulic fracture design, implementation is key
Ensuring fractures are placed correctly is a major benefit to well performance. But simply placing the frac stage sleeve or perforation clusters according to the frac design is not enough. The trick is to ensure that the fractures actually go where they can maximize reservoir contact while avoiding geohazards such as wet zones or adjacent wells.

One of the biggest technical breakthroughs has been the development of microseismic fracture mapping. This technique allows the stimulation engineer to observe fracture propagation in real time. If the fracture is going in the wrong direction, the pump schedule can be changed on the fly to alleviate the problem. Often, diverters can be deployed to steer the fracture into previously determined sweet spots. Or, if stages are being determined individually, as in the “plug-and-perf” technique, a stage location can be changed or eliminated to ensure an optimum fracture pattern. Schlumberger offers biodegradable diverter fibers that can divert the frac when deployed, then dissolve to reopen all the fractures for production after the stimulation job is completed. All diversions can be monitored using the microseismic mapping program to ensure they are going in the right place and direction.

Going hand-in-hand with stimulation technology are specific formation evaluation programs that can identify formation sweet spots, determine anisotropy, identify and orient regional stress patterns, and characterize the mineralogy to the most effective treatment program that can be designed. BJ Services (now a Baker Hughes company) swears by this approach and has trademarked its “Understand the reservoir first” process, which enables it to achieve optimal frac designs.

New fracturing techniques have been pioneered to maximize well performance on a field or reservoir basis. Using the “zipper frac” technique, adjacent wells can be fraced stage-by-stage sequentially. By holding pressure on one well stage while the adjacent well stage is fraced, the resulting stress field prevents the fracs from intersecting. Going back and forth between the wells at each successive stage is cost-effective and helps to optimize production from each well.