In the world of oil and gas, an increasing number of plays in stratigraphic traps are being made – in large part due to ever-evolving seismic technology. The Discovery Thinking forum at the annual IMAGE conference in August served to highlight some of these plays in offshore frontier basins and the role that geophysics played in their discovery.
“We are seeing more giant stratigraphic fields, and seismic is the key,” said past AAPG President Charles A. Sternbach, chair of the Discovery Thinking forum. “And, we are seeing more oil found at greater depths. Unconventional plays are migrating outside of the Western Hemisphere.”
The Venus discovery is an example of a giant field discovered in the deep waters off Namibia in early 2022, said Thibault Vandenabeele, senior prospect generator/explorationist with TotalEnergies, which made the discovery in partnership with Impact Oil, QatarEnergy and the National Petroleum Corporation of Namibia. Prior to the discovery, exploration was essentially confined to shallow waters in the 1970-90s with only minor gas discoveries.
Yet, for exploration in the deeper waters of Namibia, several challenges existed that needed to be overcome including water depth, a lack of structuration and a perception that potential source rocks were gas prone with issues to attain maturation out toward the edge of the oceanic crust, Vandenabeele explained. Furthermore, seismic data was scarce and of relatively poor quality.
The 2007 Jubilee discovery by Tullow Oil kick-started exploration of stratigraphic traps along the African and American Atlantic Margins. The Jubilee discovery “was a game changer,” Vandenabeele said. It minimized concerns about structuration and prompted the gathering of more seismic data in areas with little structuration beginning in the early 2010s. As a result of regional studies and integration, TotalEnergies farmed into a block of interest in 2017, having identified a prospect of interest on the 2-D seismic data. As 3-D seismic data was being processed, the Venus fan play was matured and firmed up. The well was spudded in November 2021 and the discovery was made in February 2022, with an appraisal well planned by the end of this year.
“The deltaic domain of the Orange Basin was calibrated by (other) wells, so we had a good idea of stratigraphy and lithology and the petroleum parameters of the deltaic systems, but conceptionally we had to image how things would develop further in the distal domain,” Vandenabeele explained. “We were able to identify a series of sequence boundaries and unconformities that gave us confidence that sands would be transported out into the basin.”
However, the Kudu shale source rock was considered essentially gas prone in the proximal domain, forcing the team to rely on geological concepts, integrating regional data and reconstructions, and seismic data to determine if an oil-prone play in deeper waters could occur.
Basin modeling with innovative concepts invoking initial thermal support before cooling and subsidence were developed to model different scenarios, and confidence was built that source rocks could be matured in such a setting.
In the vicinity of Venus, “modeling showed we were in the early- to mid-oil window, so well-placed to generate and trap liquid hydrocarbons,” he explained. “3-D had an important role from concept to prospect. 3-D gave comfort in the sedimentological interpretation. It gave more detail of lobe systems and channel systems to get more resolution and understanding of architectural elements of this fan. 3-D gave us confidence that the geometry of the trap as we had envisioned it was robust. We also gained confidence in lateral sealing mechanisms,” Vandenabeele said. “The final piece of the jigsaw was seismic response. (Amplitude versus offset) worked when looking for anomalies – one that could be interpreted as a (direct hydrocarbon indicator), so Venus was drilled as a DHI-supported prospect.”
The reservoir encountered was high quality, exceeding pre-drill expectations, and contained light oil and associated gas within an 84-meter column of net pay. The Venus play-opening discovery resulted from TotalEnergies’ high impact exploration strategy in a frontier basin context driven by regional-to-prospect scale geological and geophysical integration.
Offshore Holds Low Carbon Key
Referring to the energy transition as an “evolution of the energy system,” William Langin, senior vice president for exploration, Western Hemisphere and deep water, with Shell, stressed that the term “transition” does not accurately reflect the world’s current and future needs for oil and gas, and the goal of the industry should be about “continuing to supply the best barrels into the energy system.”
Geophysics will continue to play a great role, he said.
“All demand scenarios have oil and gas as a core part of the energy mix for decades to come, but the way in which we find, develop and produce that oil and gas also has to evolve. It’s a complete evolution of upstream, which will be the fabric of the energy system for decades to come. It is not possible to transition away from oil and gas overnight, especially with energy security coming into the mix,” Langin explained.
Like other major operators, Shell’s deep water business is an area of continued focus as it works to achieve net-zero emissions.
“These are among the best barrels globally,” he said. “They have among the lowest carbon intensity on a per-barrel basis.”
He stressed that the Gulf of Mexico is the basin “we all want and we should all love.” It is a higher-margin, lower-carbon basin that should be part of the future energy mix, Langin said.
“A lot of DHI technology started in the Gulf of Mexico and has driven further technology advancement,” he added.
Focusing on Shell Offshore’s Whale discovery in the Perdido Corridor in 2017, Langin said the discovery has become a prototype for certain capital projects because of its shorter cycle time and high yield margin barrels. It is Shell’s second deep water development in the Gulf of Mexico that employs a simplified, cost-efficient host design.
“The greatest challenge was tackling the seismic image distortion from complex salt structures, and the best decision by the team was to pull the trigger on the (ocean bottom node acquisition) survey,” he said.
OBN modeling delivered robust coverage, allowed for the optimization of well locations and a better understanding of fault compartments – ultimately leading to better development decisions. The team’s decision to move one well as a result of OBN data “has likely paid out the OBN costs – and we are talking about a 15-well development program in our view,” Langin said.
In addition, “our appraisal campaign will be impacted by this much, much better seismic data, and Shell plans to invest in OBN and other technology that drives exploration forward. It’s been much value added after the post-discovery well,” he said.
“The Gulf of Mexico is very geophysically driven. We need this technology to ultimately decide where to place exploration wells,” Langin said. “Opportunities are just sitting around now.”
Geology, Geophysics and Patience
Ted Godo, retired chief geologist at Shell, discussed the perseverance needed throughout the 10-year discovery process of the Appomattox Field in 2010 in the Gulf of Mexico.
Using analog fields to help identify potential discoveries from blocks acquired in a 2001 lease sale, Shell looked at stratigraphic sequencing and analogs that extended into the deeper waters, focusing on the Mesozoic Era. Teams looked at onshore fields for reservoir type, deliverability and geochemistry to identify potential source rocks. While drilling its first two wells, Shiloh and Cheyenne, the teams relied on rock property studies, real-time evaluations of geochemistry and paleontology, and basin modeling.
Shiloh, drilled in 2003, targeting the entire Jurassic section, yet only the Norphlet had live oil in good aeolian reservoir, Godo said. The other Jurassic and Cretaceous section had disappointing reservoir development, turning up mostly marls and carbonates. Cheyenne was drilled farther to the south, also showing little promise and pointing teams toward a third exploratory well, Vicksburg, targeting specifically the Norphlet aeolian sandstone reservoir. Yet, after hurricanes Ivan in 2004 and Katrina in 2005, activities all but halted.
Later, a small team focused on drilling the Vicksburg well to learn how far the targeted Norphlet desert sands extended. In 2007, the well encountered a thick oil-filled aeolian sandstone and basal fluvial shale resulting in a small oil discovery – but ultimately was considered a disappointment because of immoveable solid hydrocarbons found in the pores.
Yet, the team kept going, eventually deciding to drill the Fredericksburg well, and were disappointed again when the well showed the sands had thick permeability and no oil shows in the Norphlet.
It became clear that the Appomattox was the best prospect to drill in 2009, Godo said. The team looked at seismic lines for guidance. Here, the critical charge moment is much younger – in the mid-Miocene. The late charge was a major key in this prospect’s success.
Godo noted that the seal worked so well that it made for the accumulation of a giant oil field.
“We still don’t fully know the trapping mechanism that seals this 1,900-foot oil column,” he said.
Godo attributes the success not only to perseverance but relying on the opinions of others that helped keep the team open-minded. An intact core team was present throughout the process to study the wells and make consistent observations in each new well.
“Always look back,” Godo urged. “Sometimes unique circumstances and observations can alter conventionally applied play risks. Having a technically-grounded management staff to understand team recommendations and know when to call in help was extremely important.”
Stressing the importance of DHI seismic technology in geoscience interpretation, Rocky Roden and Henry Pettingill with Rose & Associates, which assesses oil and gas exploration risks, discussed how the incorporation of DHI analysis has evolved over the decades to be an integral component of prospect evaluations in many basins around the world.
A DHI is an anomalous seismic response that results from the presence of hydrocarbons, Roden explained. “Until you drill a well you don’t really know whether (you truly have) a direct hydrocarbon indicator, so you may call it an amplitude anomaly or a potential DHI. It’s very important to recognize that distinction because all amplitudes are not DHIs and all DHIs don’t display the same characteristics. To really evaluate DHIs you have to integrate the geology in a very systematic and comprehensive approach. This is necessary to properly account for all the appropriate risk elements.”
DHI evaluation has been an effective de-risking tool for more than 50 years, Pettingill said, adding that it has helped define many of the world’s largest discoveries. Quantification of data quality and the relative importance of the various DHI characteristics is critical in determining prediction accuracy.
Roden indicated that early DHI technology was vaguely understood until a symposium on DHIs in 1973 revealed the technology. This changed how companies processed and interpreted seismic data, now preserving the amplitudes for DHI evaluation. The evolution of interpreting amplitudes with offset (AVO) helped interpreters understand DHI pre-stack amplitudes in the early 1980s. But Rutherford and Williams in 1989 published a seminal paper that explained the expected AVO response in different settings by means of AVO Classes 1-4.
In 2001, a DHI consortium of oil companies started in Houston with the purpose of understanding the interpretation of DHI characteristics and to build a database of DHI prospects. This consortium has spread worldwide and presently maintains a database of more than 360 prospects in 42 basins and is still active today with 35 participating companies, Roden said.
But how does one categorize a DHI? When most people think of DHIs they think of a seismic anomalous response right at a reservoir -- for example, flat spots and downdip conformance, Roden said. However, there are other categories of DHIs, such as comparing the anomaly to other features, like a change in AVO compared to the model or unexplained events outside of the closure. Another category is DHIs that cause anomalous features such as pushdown or pulldown events and shadow zones.
Roden added, “The bottom line is, you need to look at both time and depth data to properly assess potential DHI anomalies.”
Roden alluded to a 2016 AAPG Bulletin article entitled, “Benchmarking Exploration Predictions and Performance Using 20+ Years of Drilling Results: One Company’s Experience (1994-2015),” by Kurt W. Rudolph and Frank J. Goulding of ExxonMobil. The paper concluded that the actual success rate of DHI-supported wells is 20-percent higher than pre-drill estimates. DHI-supported wells are almost 40-percent higher than non DHI-supported wells in terms of the geologic success rates, and 30-percent higher in terms of economic success rates. This paper substantiates that a DHI can have a huge impact on success rates and help improve the accuracy of predicting volumes.
So, what drives success? A consistent and objective approach considering all the data and the integration of geology, geophysics, rock properties and regional data.
“It really comes down to understanding that relationship between the seismic anomaly and the geological model,” Pettingill said.
In regard to the future, Roden said there remains room for improvement, including the interpretation of subsalt DHIs, dim spots and other subtle DHIs, low saturation gas interpretation, controlled source electromagnetics in appropriate settings, and the application of machine learning.
Sternbach and Michael Forrest, AAPG Sidney Powers Medalist, co-chaired the Discovery Thinking forum at IMAGE 2022 with a vision to integrate geology and geophysics. They are working on an exciting program of global discoveries for IMAGE 2023.