The target reservoir is nestled up against a fault, and you eagerly put down a wellbore -- but there's nothing there to produce.
Yes, it's a disappointing (and costly) event. But not necessarily a head-scratcher; the trapping fault likely was non-sealing, allowing the hydrocarbons to seep away.
Or, perhaps you're beyond discovery and into the reservoir management stage, and the reservoir's behavior has you flummoxed. You had assumed it was nicely compartmentalized by faults; now you find those quirky fractures didn't seal as well as you reckoned.
These are but two of many potential scenarios associated with faults that are prompting increased interest in fault seal analysis applications. In fact, some of the experts in the technology, because of the multitude of issues involved, refer to it more in the general sense of fault characterization.
Interest in fault seal analysis has waxed and waned since its inception years ago in the research labs of the majors, such as Shell. A number of companies have entered the field in some capacity or other, while others have exited.
But high commodity prices work wonders to trigger new and renewed enthusiasm for technologies of varied kinds, and fault seal is no exception. Operators both large and small are busy dusting off prospects that depend on faults as a sealing mechanism that were considered too risky to drill when prices were low.
They're now keenly interested in learning more about fault seal tools to guide these prospects to fruition.
In fact, "Faults: Cross Migration vs. Seal" was the topic of an afternoon-long poster session at the AAPG Convention in Calgary in June.
Faults are the most basic component of heterogeneity in reservoirs, and they are tricky devils indeed: They can hold the hydrocarbons in, or provide an escape route. They can be barriers to fluid moving straight across, or they can enhance the flow of fluid moving along them.
The ability to understand and characterize these fractures is a world removed from the days when geologists mapped a hanging wall and footwall contact on the fault surface and looked at what might be in the area of closure -- and it's all a matter of routine for some folks.
"Anytime a fault is involved, I try to at least qualitatively evaluate fault seal, if not quantitatively," said AAPG member Robert Merrill, exploration manager at Samson International in Houston.
"One rule of thumb I have is if the proportion of sand to shale is greater than .5, it raises a flag for me," Merrill said. "In a section with greater than 50 percent sand where you have sand-on-sand juxtaposition, you know you have to worry about fault seal because of leakage.
"If a prospect is on the margin of commerciality because of the fault, you may want to do full-blown fault seal evaluation."
Finding Fault
If you prefer to bypass fault seal analysis altogether, then you might want to focus on carbonate reservoirs. Because carbonates are so brittle, no one knows how well they will seal anyway, Merrill noted.
But the world of clastic sediments offers more than enough opportunity to keep legions of fault seal devotees plenty busy.
"The majority of all hydrocarbon-bearing traps are fault-related," said AAPG member David Hardy, product manager at Roxar, which recently introduced a fault seal tool that incorporates directly into the geologic model. "Faults can break up communications between different layers within oil and gas reservoirs, as well as degrading communications across the faults."
There is a growing consensus within the industry that the correct characterization of fault seals is a crucial missing step in the reservoir modeling-to-simulation workflow.
"The tendency has been to build the geologic model to put into the simulator while ignoring what happens in the faults," Hardy noted. "All you're taking account of is juxtaposition.
"As part of the faulting, there's also degradation in porosity and permeability in the fault rock caused by such things as cementation, grains that crush and break up or reduce pore throat size, clays that smear," he added. "Lots of people are building reservoir models in Petrel, Gocad, RMS, but I don't think they're taking into account this degradation of rock quality around the faults."
Fault seal is generally a factor in reservoirs with complex geometry, according to AAPG member Peter Hennings, senior scientist-upstream technology at ConocoPhillips.
"The most important thing is to get the geometry right that captures that complexity," Hennings said. "In a modern context, it needs to be done in a three-dimensional approach where you're using well data, seismic data and any interpretation simultaneously.
"Usually that means in a 3-D tool of some kind on a workstation."
It does, indeed, take a heap of multisource input to ultimately characterize or predict the sealing nature of a fault.
"Modern fault seal analysis methods use an array of data," said Rob Knipe, director of Rock Deformation Research, a long-time name in fault seal, which recently teamed with Roxar in a co-op deal to further hone the technology. Knipe, an AAPG member, also holds the post of professor at University of Leeds, where RDR commenced, and he co-chaired the AAPG fault seal poster session in Calgary.
"These data include seismic, structural and microstructural information from high-resolution core analysis," he said, "and wellbore and production data to predict fault behavior and to reduce uncertainty and risk."
Cost-Effective Exploration
If the mere thought of using this technology conjures up anxiety about depleting the bank account, relax.
"Compared to a dry hole, fault seal analysis is an inexpensive technique people can employ to test geological interpretations of fault networks," said Graham Yielding, technology director at Badleys Geoscience, which originated at the University of Liverpool and has long been a recognized player in the fault seal analysis milieu.
Yielding co-authored a presentation at the AAPG poster session titled "Fault Seal, Migration and Accumulation: An Integrated Approach."
"In a number of companies, fault seal is becoming a necessary task that prospect groups have to go through," Yielding said. "At some of the majors, you have to demonstrate that fault seal has been taken into account and analyzed -- if appropriate -- before drilling is approved."
"As an integrated major, we would not drill a prospect without considering full fault seal risk," Hennings noted. "It's part and parcel of every subsurface study, and it goes beyond the exploration realm.
"In development projects, we consider the impact of fault seal on development plans and well completion designs."
In fact, exploration and development are co-key aspects to fault analysis/characterization.
"On the exploration side, you're helping to risk traps," said AAPG member Russell Davies, U.S. operations manager at RDR. "You want to know how you might predict the sealing capacity for a particular reservoir and how much hydrocarbon column you could support against that fault and what expected volumes you might have. This is a pre-drill situation.
"In a development scenario where you've made a discovery, you want to know not just if the faults have compartmentalized the reservoir," Davies said, "but, if so, how many wells you'll need to extract the hydrocarbons."
"In the reservoir management side, where we're coming from, where you may be putting in injectors and producers, we're interested just as much in whether fault analysis shows there's a baffle to flow," Hardy said.
"There are a lot of cases where the fault degrades the nice, high permeability around it to form a baffle impacting the sweep pattern and efficiency -- for better or worse. Depending on the nature of the baffling, how it's trapped the oil, it could actually improve recovery efficiency."
Bridging the Gap
Because modern fault seal analysis demands that you know how the rocks behave and what they've been through, it helps to have a trove of data to dig into. This is where fault rock property databases come into play.
It all begins with a core.
"Companies are recognizing how important it is to get that core data, especially today in the deepwater Gulf of Mexico," Davies said. "With wells costing more than $50 million, you want to drill as few as possible.
"You want to know what properties to put in for the faults to see if you can model pre-drill the behavior of a particular well drawing down that reservoir," he noted. "You want to know how those faults will behave, whether or not they will compartmentalize.
"When you pull the core, you must spend time and effort describing the deformation and getting the properties from these faults," Davies added. "Too often, there's a tendency to say there's a fault, so lets move up a ways to get away."
Davies noted RDR is promoting a deepwater consortium where companies will pool data to form an amalgamated data set that will be far more powerful than looking at individual fields.
It is noteworthy that fault seal technology provides the reservoir engineer with valuable information, which is based on geological/faulting processes, thereby helping to bridge the gap between the two disciplines.
In fact, there's positive fallout aplenty from this technology.
"Fault seal studies do require an additional investment in time (read: money), but we feel it's worth it because there are other intangibles that are by-products of the analysis," Hennings said, "like improved mapping accuracy, better incorporation of stratigraphic detail into the geologic model and things that are usually of benefit to all aspects of the project -- not just the fault seal.
"Doing fault seal work requires that you pursue those things to a level of detail you might not otherwise perform," he said. "It requires you know your system well."