Companies spend massive sums of money to drill exploratory wells in the often-challenging offshore environment, with no guarantee of success.
Prior to drilling, they run up multimillion-dollar tabs acquiring and interpreting seismic and other kinds of expensive data.
No one would question that these commonly acquired data are essential to the exploration process.
Unfortunately, the information they provide is lacking in two key regards:
♦ They can't definitively identify the presence of a petroleum system.
♦ The quality and usefulness of seismic data can be dramatically altered by thick salt sequences, which occur routinely in areas like the Gulf of Mexico and the Red Sea.
"Typically, (companies) will do a multi-beam seismic study and pick their large structures where they hope to define if these structures are charged or not," said AAPG member Rick Schrynemeeckers, business development manager for U.S. territory at Amplified Geochemical Imaging LLC (AGI). "Then they come in to take piston cores based on predetermined sites.
"And this has not always worked well," he added.
When Anadarko implemented its Marco Polo field program, the project focused on improving the detection and mapping of hydrocarbons from petroleum systems by augmenting seismic and satellite data with additional technologies.
Surveying Marco Polo Field
Marco Polo occurs in a salt bounded mini-basin in Green Canyon Block 608 about 175 miles south of New Orleans in the Gulf of Mexico. Production emanates from reservoirs within a Pliocene-age supra-salt sandstone.
Anadarko enhanced the traditional approach by employing an autonomous underwater vehicle (AUV) geophysical survey using several technologies to acquire high-resolution seafloor and near-seafloor characterization.
"This effort included our ultra-sensitive hydrocarbon system that provides hydrocarbon detection with a thousand times greater sensitivity than traditional methods," Schrynemeeckers said. "The system can identify hydrocarbons from both macroseepage and microseepage."
He noted that hydrocarbons were identified at various intensity levels in 100 percent of the core samples, negating the need to be directly over the expulsion feature or to be there during the actual event.
"Traditional macroseep detection schemes only average a 10 percent probability of detecting hydrocarbons," he emphasized, outlining the reasons for this:
♦ Lack of macroseeps over the area of interest.
♦ Lack of sensitivity in traditional hydrocarbon detection methods.
♦ Hydrocarbon seeps often are small features not readily recognized by 3-D seismic data.
"We emphasize that seismic is important, essential," Schrynemeeckers said. "But it doesn't answer the question of whether you have hydrocarbons, especially in subsalt basins where you need to know because of high salt content or thrusting and folding."
How It's Done
He discussed the procedure that comes into play once the operator opts to take piston cores.
"Traditional methods essentially take a slice out of the piston core and analyze the gas that comes out of the core," he said. "The problem is the amount of hydrocarbons in that small piece of piston core material is not much to measure.
"On the vessel, we put an absorbent inside a jar with the piston core," he said. "It's something that looks like a fat shoestring with a Teflon exterior and absorbent pellets inside.
"As the hydrocarbons off-gas from the core, they move through the membrane and concentrate on the pellets, which keep pulling hydrocarbons out of the headspace to concentrate them more and more," he noted. "That's how you get a thousand-fold increase in detection sensitivity."
Schrynemeeckers provides a simple comparison between the method employed by AGI and the traditional approach, saying the company's concentration methodology yields a bucket full of hydrocarbons, compared to a thimble-full using the traditional method.
"This gives us more to work with," he emphasized.
It was serendipitous that the Marco Polo environs sparked yet another, although geographically distant, project.
Marco Polo is flanked by two subsalt fields, sitting beneath a salt canopy measuring between 10,000 and 15,000 feet in thickness.
"It begged the question if the more-sensitive hydrocarbon detection method could detect the microseepage of hydrocarbons from subsalt reservoirs," Schrynemeeckers said.
Before long, this was proven out in a Red Sea field having a complex geologic system.
The area was overlain by 8,000 feet of evaporitic salt and anhydrite sequences that harbored interbedded shale sequences.
Ultra sensitive hydrocarbon mapping was utilized to enhance knowledge of the structure and perhaps add clarity to the boundaries of the hydrocarbon accumulations.
Liquid hydrocarbons were detected through the 8,000-foot salt sequence.
"Subsequent to the study, a well was drilled based on the survey results and produced 800 bopd," Schrynemeeckers said," lending credence to the hydrocarbon probability maps generated by the survey."