Drilling through a salt canopy can potentially provide a faster route to the subsalt objective rather than drilling through a thick, overpressured sedimentary section in a supra-salt mini-basin,” said Paul J Cullen with Devon Energy during a presentation at the 2010 Offshore Technology Conference on 5 May. “However, numerous geological factors can complicate the drilling, leading to expensive sidetracking or casing operations.”
Some of the most high-profile and actively drilled hydrocarbon plays lie below a salt canopy of variable depth, geometry and thickness. Three of the most active areas are the US Gulf of Mexico, the Campos basin off Brazil and in areas offshore West Africa, Mr Cullen noted. Drilling through salt generally can be managed with the use of mud weights between 90% and 100% of the overburden. Use of reaming to open the wellbore prior to casing also can be used to manage stresses of drilling through salt.
Overpressured shales are commonly encountered as inclusions or in sutures within the salt, potentially requiring increased mud weights to control the flow of the plastic shales into the wellbore. However, the problem could be further complicated by adjacent geomechanically weak lithologies that can fracture due to higher mud weights, leading to complex well control issues that may ultimately require plugging the main wellbore and drilling a sidetrack.
Additionally, tar has been encountered in various situations in deepwater Gulf of Mexico wells, such as inclusions and sutures in the salt, in deep-rooted faults and in fractures below the salt and in pore spaces within the target reservoir. The tar can ball around the bit, requiring a costly and time-consuming trip out of the hole to change bits. In other cases, the drillstring may need to be packed off, requiring jars and large overpulls to retrieve the bottomhole assembly (BHA). Ultimately, a sidetrack may be necessary.
All of these situations could negatively impact the economics of a project. To mitigate these risks, identification of the hazards must extend from the mudline to TD, Mr Cullen noted. The industry has several tools available to assist in identifying these hazards, including seismic imaging, pore pressure prediction and geomechanical modeling.
Better seismic imaging identifies drilling hazards
Recent technological advances in seismic acquisition and processing significantly improved the industry’s ability to image within and beneath salt, resulting in the ability to determine subsurface structure more accurately. “Marine wide azimuth seismic surveys have been acquired over much of the deepwater Gulf of Mexico in the last five years,” Mr Cullen said. “These data sets record a broader range of source-receiver azimuths than traditional narrow azimuth surveys and result in a more complete representation of the total wavefield.”
Processing techniques and velocity modeling methods benefit from wide azimuth (WAZ) seismic surveys. Coupled with the enhanced accuracy of 3D surface-related multiple-elimination (SRME) to remove free-surface multiples from the data reduces noise within the salt layer and provides a significantly better definition of inclusions and sutures.
Another seismic tool, velocity models, previously defined only the top and base of the salt bodies. Improved seismic resolution within the salt canopy allows the larger sediment inclusions to be incorporated in the velocity model, which can improve the quality of the final subsalt image. These velocity models generally relied on the use of a simple compaction gradient of the extrapolation of sediment velocities adjacent to salt. However, Mr Cullen noted, seismic data are generally inadequate to resolve the subtleties of the subsalt velocity structure, mainly due to limited illumination angle and poor data quality of pre-stack gathers.
Geologically based velocity models have been demonstrated to be more accurate and produce a better subsalt image at the target level.
Another seismic method, reverse time migration (RTM), which uses the two-way wave equation, resulted in marked improvement in subsalt imaging, particularly steep dips and sediments adjacent to the salt, without the processing artifacts associated with earlier migration algorithms. Sutures are more clearly defined and can be correlated from one drilling location to another to predict the potential for lateral transfer of pressure from deeper to shallower in one section.
“The latest development in velocity modeling is full waveform inversion,” Mr Cullen said. “This is an iterative scheme also using the two-way wave equation, which seeks to minimize the differences between the acquired data and the wave field predicted by the model.”
The result is an optimized velocity model with higher quality images.
Pore pressure prediction
“Pore pressure prediction has been a standard requirement for well engineering to facilitate planning of a safe drilling and casing program with adequate contingency for unexpected well control events,” Mr Cullen said.
Drilling engineers have historically relied on offset wells as analogs for a new well design, using mud weights, drilling reports and formation pressures, if available, to predict formation pressures. Recently, the use of seismic velocities for pre-drill geopressure prediction has become a common practice, particularly in undrilled basins or in remote locations.
However, reliable pre-drill pressure prediction from seismic velocities requires that they are checked and calibrated against a suitable offset well. Also, while seismic velocities can yield accurate pressure predictions above the salt layer, they are generally inadequate to resolve the subtleties of the subsalt velocity structure. Advanced 3D model building tools and workflows allow a “hybrid” model to be produced that integrates seismic velocity information above the salt and well-based velocities below the salt.
The industry also has produced a range of logging while drilling (LWD) borehole seismic tools that can deliver reliable data with which to provide real-time updates to the velocity model and resulting pore pressure model to the driller. Real-time check shot and interval velocity data combined with the capability to look ahead of the drill bit can provide invaluable information necessary to reach the geological objective. Additionally, formation pressures also can be acquired with LWD tools to provide direct measurements to recalibrate the pre-drill pore pressure model in real-time.
A critical interval in any well that is drilled through a salt canopy is the salt exit point. Numerous wells have lost days of productive time due to well control issues when exiting the salt. Methods to mitigate the risk include setting casing just above the predicted base of the salt to allow mud weight to be reduced for salt exit, and a “ground hog” strategy that involves drilling small sections of the interval immediately below the salt to evaluate pore pressure conditions before drilling ahead.
“These geomechanical complexities can be modeled pre-drill using 3D finite element analysis,” Mr Cullen explained. “The 3D FEA simulations are the only way to account for the influence of the creep behavior of salt on the stress state in the vicinity of a salt body.”
Like the new seismic imaging technologies, FEA has only recently become viable with the availability of program “parallization” and economical massive computer capacity. The balance between the high mud weight required when drilling through the salt and the low mud weight required to avoid losses immediately outside the salt body can be based on realistic predictions, Mr Cullen noted.
With information available in 3D, as well as using straightforward methods to map the simulation results onto a well trajectory, wellbore stability can be assessed for a number of well trajectory options, optimizing the salt exit location from a mechanical point of view as well as highlighting subsalt drilling hazards.
“Recent technological advances in seismic imaging, pore pressure prediction and geomechanical modeling have had a commercial impact on the exploration and development of offshore resources by improving drilling efficiency to reduce finding and development costs,” Mr Cullen said. “This has been made possible largely through investment by operators and service companies to develop new tools and surveying methods coupled with advanced algorithms and massive computing facilities.
“Continued investment in these areas will contribute to further drilling optimization to reach the extreme and ever-increasing depths of the subsalt hydrocarbon reservoirs,” he concluded.