Seismic while drilling shows well control potential

Gene Kliewer
Technology Editor,
Subsea & Seismic

Seismic while drilling (SWD) is a technology currently in development that shows promise in helping prevent loss of well control while drilling in deepwater. Once such systems are available generally and in a practical, reliable form, another Macondo disaster might be avoided. This reason, if no other, should spur rapid development of practical and effective SWD tools.

SWD became a topic of discussion at the Bipartisan Policy Center for the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. Bob Radtke of Technology International addressed the general topic for the commission.

Following are selected questions from the committee and Radtke’s responses:

Committee: What is the current portfolio of technology available to minimize drilling risks? How often and where is it being used?

Radtke: Surface seismic surveys provide the initial reservoir information for well planning deepwater wells. Seismic techniques are being developed to better image potential drilling hazards, such as unstable shallow gas pockets and abnormal high pressures ahead of the bit using so called “look-ahead” seismic. Accurate, high-resolution seismic data often are unavailable for critical deepwater projects because of inherent limitations of surface seismic technology and difficulties in getting an accurate characterization of formations where salt layers are present.

Using borehole seismic technology throughout the drilling process can play an important role in generating more accurate, higher resolution seismic data to reduce the often substantial risks and uncertainty associated with deepwater drilling.

Borehole seismic systems with a surface noise source and a downhole receiver are available commercially. However, these systems are expensive, cumbersome to deploy, have difficulty working in a salt environment, do not provide the ability to “look ahead of the drill bit,” and information available at the surface for real-time decision making is constrained by the bandwidth of the measurement while drilling communications link, making SWD less practical in deepwater applications.

Availability of SWD with a downhole noise source could overcome these limits. Seismic while drilling would help reduce uncertainty and risk, and improve safety in the deepwater well construction process.

A workshop sponsored by the Research Partnership to Secure Energy for America (RPSEA) invited 125 industry experts on the basis of their individual technical qualifications. The workshop was held to identify and evaluate a diverse group of technologies that would help minimize drilling risks. Afterward, workshop participants identified those technologies that would be of greatest value for GoM deepwater drilling and should be the industry’s highest priority for development.

The two areas selected as highest priority to prevent another GoM well blowout were early detection of gas influx and better SWD data. Looking ahead of the bit, SWD using a downhole source is practical, and will, after sufficient funding becomes available, provide real-time seismic images used to accurately determine pressures ahead of the drill bit.

Committee: Are drilling risk management processes adequate for deepwater? Are there meaningful differences in the risk profiles of different offshore oil and gas wells subject to the moratorium?

Radtke: There are differences in risk profiles between wells due to differences in geological complexity, pressure profiles, and degree of uncertainty about actual downhole conditions. These well differences are magnified by how each operator and drilling contractor chooses to manage risk and uncertainty. Each operator and drilling contractor implements procedures and processes which best suit the company’s perceived needs, some with greater emphasis on selected elements. Some stress well planning while others emphasize the reliance on pre-drill seismic data alone, 3D VSP, seismic while drilling, post well seismic data, basin modeling, workflow planning, training, use of real-time data, adoption of emerging technologies versus the primary use of legacy technologies; decision making processes; and cost reduction objectives.

Committee: What specific criteria distinguish the risk profiles of different offshore wells?

Radtke: The critical issue is the degree of uncertainty about the actual pressure profile where the well is being drilled. Deepwater drilling must deal with maintaining the correct mud equivalent static density (ESD), while dealing with low fracture gradients, trip gas, and kick circulation. Unknowns begin with kick tolerance.

This is especially important when drilling through salt structures. Surface seismic data at depth has insufficient resolution to prepare the driller to correctly maintain proper well pressure control. With less experience drilling deepwater wells and limited seismic data – particularly near salt structures that mask surface seismic signals – the risk and uncertainty are greater. Thus, reservoir models provide less insight as drilling proceeds. While also true in shallower GoM waters, abnormally (unanticipated) high pore pressures are encountered hundreds of feet sooner than predicted. Resulting well control issues balance the pressures within the wellbore.

Extreme water depth is, of course, a challenge for today’s ROV fleet when it comes to well intervention. The availability of tools with high pressure ratings is less of a problem when compared to electronic tools with higher borehole temperature ratings. High-pressure/high-temperature wells are defined generally as those with greater than 10,000 psi and 175° C (350º F). Logging geological zones to predict pore pressures and the need to deal with smaller differences between pore pressure and the formation fracture gradient intensify the well control requirements and makes vigilance by the crews and onshore data centers essential. Appraisal wells are, of course, drilled vertically and deviated/horizontal drilling has even greater uncertainty because less data is available for geosteering.

Committee: What is the best practice process for approving and making design and operational modifications?

Radtke: Deepwater well planning scenarios and drilling and well control procedures are under constant review by operators. Independent consultants present alternative solutions. Norway and the UK regulate and monitor the content of these studies. At one time, it was reported that regulations and guidelines for well planning could become uniform for all deepwater operators. After sufficient review, one could become an advocate for a uniform code for guidelines and training created jointly by industry and supported by professional industry organizations. The former MMS has always been invited to participate in such activities. As for other industries, such as automotive and aircraft, guidelines become domestic and international ISO standards.

Committee: What is the best practice for anticipating failure scenarios?

Radtke: Original equipment QA and QC procedures and inspections are under the control of equipment manufacturers. Most often, operators and drilling contractors require contractors to utilize ISO 9000 and 9001 standards, and inspect and qualify their facilities and test equipment.

The MMS (now Bureau of Ocean Energy Management, Regulation, and Enforcement) routinely participated in industry workshops and forums intended to improve training as well as drilling and production equipment and services. This should continue, with increased emphasis on reviewing (and when necessary providing funding jointly with industry organizations) to accelerate efforts of safety related issues.

Committee: How easily could off-site, onshore monitoring facilities be established to enable third party experts and inspectors the ability to monitor drilling activities and well conditions?

Radtke: The first data centers were in Lafayette, Louisiana, operated by The Superior Oil Co., and Tenneco West. At Superior in about 1980, the first benefit was the ability to detect a drill pipe wash-out before the rig crew could. Only then did contractor drilling supervisors on land become aware of the benefit of the center, even though it was located only a short distance from their offices.

They permit off-site monitoring, modeling, and, as a minimum, advisory notices to the rig of pending problems and proposed solutions.

Committee: Are the current safety and environmental management systems adequate for deep water?

Radtke: There are differences in the current safety and environmental management systems across the world depending on local regulations and the relative risk tolerance of the participants.

However, these differences are less meaningful than the degree of commitment of all participants to consistently adhere to the standards, wherever they are set, and to invest in the best available technology. For example, risks could be reduced if regulators insisted that the highest resolution seismic imaging possible be included in each deepwater GoM well plan. Worldwide, there are significant differences in regulatory practices, created often by countries such as Brazil after the sinking of a floating platform and Norway reacting to a disaster in the North Sea. Often operators and contractors in the GoM adopt North Sea practices, where emerging/safer technologies are often first adopted.

Committee: How should regulations evolve to handle changing deepwater technology and drilling horizons?

Radtke: As the first step, review past regulations and guidelines that have been weakened or cancelled. A review of industry-proposed priorities and, if necessary, impose guideline and regulations that create accelerated commercialization of direct safety emerging technologies that are shown by a managed risk analysis to be of the greatest benefit to pressure control practices and, thus, minimize the possibility of another well blow out in the GoM.