On the continents of Africa and Asia, seismic data plays a major role in exploring for and de-risking gas plays – some in untested areas. At this year’s Discovery Thinking forum at the International Meeting for Applied Geoscience and Energy in August in Houston, presenters discussed the challenges leading to their discoveries and the value of the seismic data that led them down the right paths.
“In Zimbabwe, the hunt requires gathering all the data and patiently stalking the prize despite many above-ground challenges,” said Charles Sternbach, AAPG past president, co-chair and originator of the Discovery Thinking forum. “In Indonesia, technical integration of the geology and DHIs (direct hydrocarbon indicators) have paved the way for an exciting new exploration phase.”
Zimbabwe
Until recently, oil and gas prospects in Zimbabwe looked dim for decades. ExxonMobil abandoned an exploration program in the 1990s, believing the untested onshore rift basin it was exploring contained more gas than oil. And, the government at the time wasn’t inclined to make commercial gas opportunities enticing.
Yet in 2017, a new government in Zimbabwe emerged and so did an Australian-based operator called Invictus Energy, formed in 2011 to explore Sub-Saharan Africa and Zimbabwe after a 20-year industry hiatus in the country.
In 2018, Invictus entered the Cabora Bassa Basin in the northern part of the country with not much to go on, except 16 gigabytes of mothballed 2-D seismic data shot by ExxonMobil in the ‘90s and archived at the Zimbabwe Geological Survey.
One particular line caught the attention of Scott Mac millan, a reservoir engineer with Invictus. It showed a massive structure, the Mzarabani anticline, which measured 200 square kilometers under closure.
Because this data was not on-line, it was not widely known nor shared. It became a goldmine for Invictus, which spent its first three years reprocessing the 2-D data, supplementing it with infill data, and drilling one well.
The Cabora Bassa Basin is a trans-tensional rift basin – part of the Karoo Basin development along the southern margin of Gondwanaland, associated with major continental thrusting to the south. “What is very different about the Cabora Bassa and why we decided to make entry into Cabora Bassa rather than other basins was the presence of a very, very thick Triassic sequence,” Macmillan said. “This was the key differentiator, we felt, between these and other Karoo plays that have typically been chased, which are Permian.”
Their key target was the Upper Angwa sandstone, as outcrops had suggested both source rock and reservoir were present, Macmillan said.
However, one of the key uncertainties was the lack of biostratigraphy or palynology for calibration, making dating the formation difficult. Trying to constrain basin modeling and charge time were also challenges.
Using 650 kilometers of Mobil’s seismic lines, Invictus mobilized a team to transcribe the field tapes, infilling where necessary. “Mobil used high-quality 9-track tapes. We were grateful to get an entire dataset that had been sitting there for 25 years. It was quite an amazing feat,” Macmillan said.
Furthermore, the 16 gigabytes of data could be fully utilized due to advances in computer processing power compared to what was possible in the 1990s, allowing Invictus to reclaim a vast amount of data. When reprocessed, it produced images with high clarity, detail, reflectivity and fault definition.
The outcrops revealed a very high-quality source rock and reservoir, featuring clean sandstones. Samples from the primary source rock interval analysis revealed “good to excellent” source rock properties – capable of generating both oil and very rich gas condensate,” Macmillan said.
Yet calibration was an issue without offset wells. “How do you determine what horizon is what? We did this by taking a geological sketch map…generated in 1998, using that and tying in the seismic facies to the outcrops to make sense of the various units,” he explained. “This is not exactly science but a little bit of art as well.”
Because the team was working with widely spaced seismic lines, they relied on reprocessed legacy gravity and magnetic data, which was used to infill the lines and observe fault trends, particularly near the Mzarabani structure. By the end, they were able to identify stacked potential as well.
An independent estimate for the Mzarabani prospect, as it was called at the time, was 8.2 TCF of gas and roughly 250 million barrels of condensate.
The next step involved infilling Mobil’s seismic lines and seismic data with Invictus’ own infill survey of 840 kilometers of 2-D seismic lines – data they shot in 2021 during the pandemic.
Invictus was one of the first companies to use the STRYDE nodal system, which boasts the world’s smallest, lightest, and most cost-effective autonomous nodal technology. This, Macmillan said, allowed for rapid retrieval and development with a lower environmental footprint.
In the end, the team was able to identify a new play, which will likely set up a system of East African rift system discoveries and the String of Pearls, as seen in Kenya and Uganda, Macmillan said. A second independent assessment estimated the play to contain 20 TCF of gas and 845 million barrels of condensate – with the potential of more than 1.2 billion barrels on the basin margin play.
When it came time to plan for the first well, called the Mukuyu-1, Invictus was again met with the challenge of calibrating its seismic data, in terms of time and depth conversion, with no offset well data. It found the solution in velocity displays that provided “geological looking” responses, Macmillan said.
“Deciding on where you are going to test a 200-square kilometer structure is no mean feat when you’ve got no well data in the basin,” he added. “Trying to risk and rank all the horizons in your target – you don’t know which ones are going to work.”
In the end, the team ranked each horizon by how they thought each play was going to “sit up and work.”
They chose an aggressive well design to test all potential targets – a 33-degree inclined well down the backside of a major fault. “We didn’t want to have any regrets that we didn’t test any of the amplitudes, and so we ended up designing and drilling a pretty jazzy well for the first one in the basin,” he said.
Invictus chose not to farm out the project, making the operator the sole funder and risk taker – nearly going bankrupt at one point, Macmillan shared.
Amid supply chain disruptions, faulty equipment, the Ukraine war, exotic wildlife visitors, and a “cacophony” of moving parts, as Macmillan put it, rig mobilization began in 2022. Drilling through seven stacked targets was estimated to take 50-60 days, and Invictus received good news on Day 47. “From an uncalibrated perspective, our team did an absolutely unbelievable job,” he said. “All of our horizons came within about 50 meters of prognosis. The first reservoir we went into encountered 100 percent fluorescence and 135 times above background gas.”
Upon reaching total depth, they encountered more hydrocarbons, and the primary well logs revealed multiple hydrocarbon bearing zones.
However, the heavy mudweight used to control the well caused high overbalanced borehole conditions, and coupled with wireline tool failures, prevented them from completing formation sampling, so they were not able to officially declare a discovery.
Yet in 2023, the Mukuyu-2 was spudded 7 kilometers away and 450 meters updip from Mukuyu-1. At last, a discovery could be announced in the Upper and Lower Angwa.
“We have opened up another petroleum province with Mukuyu,” Macmillan said. “We have a lot of exploration ahead of us in this space and we are quite excited about what we have seen. We now have a deliberate sequence strategy to develop this.”
Invictus is currently planning for appraisal wells and further exploration, with its main goal to provide energy to power plants to help alleviate the pervasive energy poverty in the country.
Upon reflection, Macmillan shared several lessons learned when drilling the first wildcat well in an untested basin: “Leave no stone unturned. You’ve got to do down every rabbit hole to figure out what’s going on. You also need the freedom to fail so that no one is afraid of testing wild ideas,” he said. “Question the status quo among the held truths. People thought we were crazy going into a frontier basin and that we would go home with our tail between our legs.”
Lastly, he said he would be remiss to deny that the right luck, timing and geology no doubt play an essential role in successful discoveries.
Indonesia
In an effort to unlock a gas play near Indonesia, Harbour Energy turned to innovative seismic data to explore the Timpan Lead in Andaman Sea. While seismic attributes and rock physics played an important role in derisking the presence of gas, more detailed integration between geophysics and geology is important to assess the geological aspects of the prospect, such as reservoir quality. Understanding how the reservoir behaves remains Harbour’s focus in this new frontier area.
Legacy 2-D seismic lines were acquired in the Andaman II PSC exploration block from 2006 to 2012, and early indications of DHI anomalies in a series of structures were seen in the Late Oligocene Bampo Sandstone formation, said Nauvall Juliansyah, a geophysicist with Harbour. Although several offset wells were drilled through the Bampo sandstone, only one significant gas discovery was made.
Yet the presence of DHIs from the legacy data inspired Harbour to initiate a multi-client 3-D seismic acquisition in 2019. The survey covered approximately 10,000 square kilometers across the North Sumatra Basin, including 2,700 square kilometers in the exploration block. The survey continued with full waveform inversion and pre-stack depth migration seismic processing of the acquired seismic data.
The seismic 3-D PSDM confirmed the presence of DHI anomalies with prominent flat spots in many of the structures within the block. The Timpan lead – named after a local dish of bananas and coconuts – was believed to have the greatest potential, Juliansyah said. In fact, the new survey raised Timpan from “lead” to “prospect.”
In studying the regional well correlation data, Harbour concluded that Bampo sand distribution was widespread and present in all offset wells. It seemed likely that Bampo sand was also present in the prospect. Yet only one offset well – north of the Timpan prospect – was a gas discovery.
“The challenge here is that the reservoir depth of this offset well is shallower than Timpan, so it was challenging to look for analogs,” Juliansyah said.
Harbour had to “play around with a lot of AVO (amplitude versus offset) and angle stacks,” to predict the hydrocarbon content and reservoir quality, he added.
The new data derived from gather conditioning work improved the gather flatness (the flattening of pre-stack seismic events), resulting in significant imaging uplift at the Timpan structure, Juliansyah said. Further gather conditioning showed that the Timpan prospect was a four-way faulted structure with a class II AVO anomaly with good conformance between DHIs and the structure.
Amplitude versus angle modeling was performed to estimate the gas saturation and porosity of the Bampo sandstone reservoir.
A spectral decomposition extraction at and around the Bampo reservoir seismic event showed evidence of a reservoir system feeding into the Timpan prospect. This helped to lower the risk of reservoir effectiveness, Juliansyah explained.
Because good quality source rocks were not encountered by the offset wells, source rock quality remained uncertain. Yet limited petroleum system modeling suggested that hydrocarbons were charged from fluvio-deltaic to marine shales of the Upper- to Mid-Parapat formation at the Timpan graben, directly below Timpan, Juliansyah said.
A rock physics study, which examined the relationship between the physical properties of the subsurface rocks and how seismic waves interacted with them, conducted at the offset well found 20 percent water saturation – a good match with in-situ logs.
And, 2-D forward modeling – a technique that uses geological information to create synthetic seismic models – for internal shale thickness evaluation revealed that 25- and 50-foot shale intervals seemed to have the best alignment with the full stack seismic data, he said.
Nine different AVA models were used to test against the gather response from the conditioned gathers. The 20 percent water saturation model gave the closest response to the gather. Porosities of 19, 23 and 25 percent were the closest models to the conditioned gather at Timpan, he added.
A geological probability of success (POSg) of 31 percent was estimated for the Timpan prospect, with the key risk being reservoir effectiveness because of a lack of Bampo sand at a similar burial depth, and source rock quality because of limited well calibration.
A solution was to employ a seismic amplitude analysis module DHI uplift tool, which is a quantitative assessment of the uplift of a direct hydrocarbon indicator. “A robust DHI was observed in Timpan,” Juliansyah said. “We thought it would be a 42-percent uplift, so we combined this with a 31-percent POSg, resulting in a 73-percent possibility of success.”
The Timpan-1 well was drilled in 2022, finding an approximately 400-feet gas column at the Bampo Sand Interval and gas flows of 27 million standard cubic feet per day and 1,800 barrels of condensate per day. It is the first major gas discovery in the Bampo Sandstone in the area and has opened up the Bampo Sandstone play in the region, Juliansyah said.
Harbour has since identified additional DHI prospects on western side of the exploration block. “It’s not always a very easy path when it comes to exploration prospects,” Juliansyah said. “There are more challenges coming after the Timpan-1 well, but Timpan has opened so many more opportunities for exploration activities.”