Any exploration project starts with a full geologic evaluation, including risk analysis and economics. Although many other factors are at work in the assessment, the focus in what follows will be on the geosciences components. When the evaluation has been carried out and the project is validated for a final investment decision, the person in charge at the end of the cycle – say, an exploration director in contact with his team (and sometimes under pressure) is immersed in the solitary position of a “go/no go”-predicament.
This is even more true in a frontier play or a new play in a mature area when, even after all de-risking points have been dealt with, there remains a high degree of risk. In practice, this means a much greater chance of failure than success, which makes the final step of the process critical and uneasy.
Thinking back about what was typically dominant in my mind at that precise moment when it was time to take the plunge or drop it, I found out that the main criteria were often simpler than expected. The issue will be framed along the following lines:
- A few real-life examples will be described, either from personal experience or informed through stories, which became more familiar through generous discussions with their related actors and decision-makers.
- These historical examples are meant to illustrate a “posteriori” a manager’s state of mind during the process and some valuable lessons one can learn from the stories.
In part 2 of this story next month, I will share some thoughts about the related evolution of the profession from a management perspective.
The Mahakam Delta Story
The Mahakam Delta Basin is one of the oldest petroleum provinces of the world, with its first fields discovered and exploited onshore Kalimantan, Indonesia, from the end of the 19th century until now. After World War II, exploration picked up again on new territories in the basin, extending toward the delta itself and the offshore. Structurally speaking, these operations took place over three large concentric structural trends, named inner, median and external. Bekapai belongs to the first phase of structural exploration, and Peciko was part of the second phase of a stratigraphically oriented program.
Total had acquired a 50-percent operating interest in a block held by Japex Indonesia in the Mahakam Delta Basin of Kalimantan, straddling offshore and coastal swampy areas. Six dry wells had been drilled on the block with no commercial success whereas some oil and gas fields were being developed elsewhere in the same basin. At that time the exploration and production director of the company advised the local exploration staff that they might get some money for a final well. If dry, that would mean not only abandonment of the permit but also all the operations in Indonesia.
Recently I was able to interview Jean Gérard, the senior geologist who oversaw the local operations at that time.
Two options were on the table. We could redrill an anticlinal feature already drilled unsuccessfully by the Japanese company at OMC-1, the only well on the block. There was still some doubt regarding the true geometry, due to the poor seismic quality of past programs. Or we could drill an undrilled structure, which was preferred by the exploration head office in Paris. They were reluctant to support the questionable idea of drilling a “dry” structure again.
To help resolve the uncertainty, Gérard asked for a budget to shoot two crosslines over the structure, and he won his case. This new program resulted in finding that:
- One horizon lower than the previously mapped level showed significantly more relief, and
- That horizon could be related to a package of sand found dry in the only available control well.
Gérard also suggested that this package could be thickening up southward from OMC-1 toward the highest part of the structure due to a retrograde facies evolution at the transition from the delta front to the delta plain. Another consideration was the proximity of a distributary of the ancient delta, the understanding of which had improved thanks to the previous drilling. He concluded that a significant area updip of the sands remained untested, and he favored the redrill option. Gérard was supported by the management of the subsidiary Philippe Magnier, and thereafter by Claude de Lapparent, the area manager for all operations in Southeast Asia. De Lapparent was a geologist at the highest level of the decision-making process at that time; he fully endorsed the concept, based largely on some geological fundamentals which were the dominant driver of the decision.
Bekapai-1 was not drilled on the very top but for operational reasons slightly downdip. It found oil and a first test produced 20,000 barrels of oil per day. The field covered 20 square kilometers and produced up to 60,000 barrels of oil per day. As a result, exploration picked up again in the Mahakam and large fields were found on the three trends of the basin (see next story).
Gérard must be fully credited with the discovery. He truly saved the day for the permit and the company in Indonesia and set the stage for future developments to follow. It was not his only success, and his name is closely associated with the discovery and development of two giant fields in the Viking Graben in the North Sea, Alwyn and Dunbar, both operated by Total.
Lesson: The French expression “qui ose gagne” (he who dares wins) can express the difficult choice and extremely audacious decision to redrill a prospect seemingly condemned by a previous well. It captures the strength of conviction and geological vision that led to accepting a high-risk gamble.
Peciko-1 and the Second Life of the Mahakam Basin
In the middle of the 1980s, oil production started to decline and the interest was shifting to gas, which had become a commodity in high demand. Through visits of the exploration staff to our Indonesian subsidiary, we realized that, although an efficient petroleum system was obviously present in the area, it had not been fully understood. This justified a fresh look. We decided to establish a small multidisciplinary group of explorers in Balikpapan, near the field operations, to review all available data, work on a synthetic, regional approach and come up with new ideas. The group was composed of G. Choppin de Janvry, Y. Grosjean, B. Loiret and J-L. Piazza.
Their focus would be first on the charge aspect: locate the actual kitchen and understand the migration process, fluid distribution etc. Second, as all available anticlinal structures had already been explored (except some on the external trend), they focused on potential stratigraphic traps and therefore a full reinterpretation of the sequence stratigraphy of the area. This was extremely difficult due to the bad quality of the seismic. It took them more than a year to come up with a clear picture of sequences and all possible facies changes.
They ended up recommending, as a primary target, a stratigraphic prospect close to and well exposed to the main kitchen (found for the first time to be within the syncline present between the internal and medium trends). It was located over a south-to-north-dipping nose and north of a facies change which could provide an updip seal linked to the transition between the sandy delta front and the under-compacted shaly part of the prodelta. The concept was to establish a significant extension of the gas found in Peciko-1 (which had been drilled on a small culmination) over a large part of the nose.
There was no assurance of a satisfactory geometry of the updip closure. There was also the risk of insufficient gas volumes and connectivity linked to a possible lenticularity of thin reservoirs in this part of the delta. Such risk was mitigated by a core-drilling campaign on point bars of the modern delta representative of the expected facies in the subsurface, which found a considerable lateral extension of the sand bodies. The mean value of the expected unrisked reserves was 0.7 trillion cubic feet with a maximum value of 1.6 TCF and a 30-percent chance of success.
The project involved two main decision drivers, the fundamental charge and the suggested trapping criteria of the petroleum system. It was fully endorsed by management, and the first well (NW Peciko-1, drilled north of Peciko-1) found a column of gas four times thicker than what had been expected, composed of numerous stacked individual flow units. Further delineation qualified the field as a giant (more than 6 TCF), and related pressure studies led to a mixed stratigraphic and hydrodynamic model to explain the result. It’s important to recognize the previous work by explorers who helped build a considerable database and knowledge necessary for this synthetic undertaking.
Lesson: The takeaway from this story is the value to be found in a persevering synthetic effort over time by a carefully planned team with the chemistry of complementary skills. The new field model was applied to previous gas discoveries in Tunu, north of Peciko on the same median trend, allowing a considerable expansion of the field both deeper and laterally. The two fields brought the production level of the block up to 500,000 barrels of oil-equivalent per day and helped build additional LNG trains at the Bontang plant. It was a huge industrial and economic success.
Cusiana, a Surprising Giant in the Colombia Foothills
This play was found and proposed by geologist Jean Ferrat, who oversaw the South American region. He came one day to my office and said, “Bernard, you cannot miss this opportunity.” I had known him from our common time at the IFP School (like Jean Gérard of Bekapai fame), knew that he was a great, intuitive and experienced geologist and of course listened to him with attention.
The proposed farm-in involved drilling in partnership with BP a deep, costly well in the foothills of Colombia’s Eastern Cordillera. His play had already been drilled several times over with some shows but no commercial success. However, a well-defined faulted anticline had been identified for the first time by the rights owner (Triton) after a long period of mediocre seismic imaging of the area, which was one likely reason for previous failures. The regional stratigraphy was well known from past wells, while the petroleum system analysis was a high-risk element. This was due mainly to the dubious poroperm qualities of the deep Eocene sand reservoir, as reflected by poor tests. There were large doubts regarding the charge-versus-timing relationship. The tectonics of this part of the Andes are extremely recent, in the 4 to 6 million years range.
The whole exploration team was very much in favor, and when the project came to the final decision point, I kept in mind the two following ideas. First was the presence in the projected stratigraphy of a mature source rock equivalent to the famous super-rich La Luna of the giant fields of the Maracaibo Basin. Second, Jean mentioned two oil fields in the same foothill tectonics on either side of the border with Ecuador, a full 500 kilometers south of our prospect. He thought they bore witness to a possible favorable timing applicable to the whole Cordillera. In retrospect, these two points, in addition to the potential size of the target, made me enthusiastically follow Jean and the team’s recommendation and tip the balance to go ahead despite the widely recognized high risk (chance of success 15 percent, unrisked mean reserves of 175 million barrels of oil equivalent, maximum 350 million barrels).
Note that credit for the discovery goes mainly to one man’s creative, inspiring approach and to the team of geophysicists for confirmation of the potential volumes. To finish the story, two more reservoirs of Paleocene and Late Cretaceous ages contained oil and gas, which made the reserves almost three times greater than the initial estimated maximum. The reservoirs were also much better than expected, a quality linked to an exceptionally favorable poroperm relationship. The cherry on the cake, a giant sister structure named Cupiagua, was found later, and the two fields combined produced up to 500,000 bopd.
Lesson: Optimism and proceeding without too much hesitation against the objective chance numbers are the rule of the game in frontier plays. Such attitude is inseparable from trust in the strong (and convincing) position of the “pusher(s)” of the concept.
Angola’s Challenging, Uncharted Deepwater Plays
The Elf exploration staff made a strategic decision as early as 1988 to consider deep offshore opportunities in new areas not yet opened for exploration. Although not restricted initially to these two countries, the interest was soon focused on Nigeria and Angola, already with established operations including significant production. Lengthy discussions, mainly with the African district exploration chief at the time, André Coajou, have revealed the relevant sequence of events and an understanding of the historical drivers at his level of critical decision-making.
The main reasons for such interest were rather simple: Find new permits to keep production growing and focus on the two most interesting countries, Nigeria and Angola, offering geological analogy between basins in the (then named) Gulf of Mexico and Nigeria in one case, and the Campos deep offshore and Angola in the other case. Both the GOM and Campos bore witness to highly successful exploration and production operations, and similar basins on the other side of the Atlantic were unexplored deep offshore. From a geoscience point of view, the experience gained by Elf in the GOM as well as solid regional knowledge of the areas of conventional water depths adjacent to the open areas could be crucial assets in whatever evaluation work would have to be carried out.
Although the district acted in parallel for both Nigeria and Angola, we will limit ourselves to the latter country. The decision to go ahead was approved, which was not so easy, Coajou said, the focus being on large, identified structures at Cretaceous Pinda carbonate level (see seismic line). His department started to gather data, including a 9-by-4.5-kilometer spec survey over the deepwater areas known to be opening soon. Work began quickly in 1990 on a comprehensive regional synthesis to evaluate and rank the areas. This evaluation by a group composed of D. François, C. Fresnay and R. Evrard, was available in 1991. It took into account the negative results of a well (Sembo-1), Tertiary sands found in two wells (Soko-1 and Oryx-1) and the delineation of new blocks by Sonangol extending to the west.
This study ranked what became Block 17 at the top. It was located over the best areas of potential maturity of the main identified Upper Cretaceous source rock, which could be mapped over the margins of Tertiary depocenters. Several reservoirs could be present, most importantly the Pinda carbonates. These were the primary producing reservoirs on adjacent Block 3, operated by Elf in conventional water depths, and present over easily recognized gravity structures. There were also some more speculative Tertiary turbidites, as in Campos.
This carbonate structural framing was in André Coajou’s words, a management “dealmaker,” because it could be easily mapped and evaluated with the economics, whereas Tertiary potential targets over larger anticlinal features, ill-defined at this stage, were quite speculative. Reservoirs drilled on such targets so far had poor reservoir quality. Two arguments, source maturity and those concerning the drilling program to follow, were fully endorsed by two exploration directors, Paul Dubois and Daniel Fournié, in succession during the period.
Elf obtained a 50-percent operating interest in Block 17 in 1993. The first well, Margarida-1, was drilled on the block in 1994-95 without positive results, but enabled confirmation of the Cretaceous source rock. It also allowed calibration of the maturity, identification of Tertiary turbidites and location for the second well, Girassol-1, in 1,300-1,500-meters water depth on an anticline at Tertiary level with some amplitude features. Simply, the decision drivers were made possible by seriously questioning the initial focus. In other words, the basics are OK if they are supported by previous hard work; the same rule was applied in the Peciko example. The block delivered several giant fields and a mutibillion-barrel family of fields, not producing from the initial carbonate primary targets but from several rich lobes of Oligo-Miocene turbidites that were mapped and evaluated with full detailed sedimentology through high-resolution 3-D seismic and abundant direct hydrocarbon indicators.
Lesson: Utilize analogues in the choices of country and basin targets and consider the role of regional synthesis at the basin level to focus on the best blocks. Don’t hesitate to modify the objectives and change plans depending on the results of ongoing operations and external constraints, like the final announcement of the block’s limits.
Kashagan, a Geological No-Brainer
Kashagan was simpler than the previous examples from a geoscience viewpoint. However, this champion prospect came with extreme operational challenges.
With the rumor of a possible opening by Kazakhstan of part of the offshore Caspian Sea to exploration, most major companies started to consider being part of the action around 1990. The North Caspian Basin is a circular intracratonic basin which contains several giant onshore fields on its margin, including Karachaganak in the north (gas and condensate), Tengiz (oil) in the east and Astrakhan (oil) on the Russian side in the west.
Some old available seismic shot during the Soviet period indicated a huge structure located in the shallowest part of the sea. It was thought to contain the same thick reefal Permo-Carboniferous reservoirs, but drilling had not taken place so there was no proof, of course. The technology and equipment for such shallow water operations were not available there at the time. There was also a serious question concerning the sealing factor, as an overlying thick salt formation might display several windows with obvious negative effect. The chance of success was estimated in the 15 to 20-percent range but improved significantly above 20 percent after new seismic. The scarcity of data made it a true gamble. The potential size was huge though, and I remember having said during an executive committee meeting that I could not imagine a larger prospect reserve-wise than this one (and I haven’t changed my mind since).
The operational risks were so challenging that it is worth listing them briefly: difficult logistics linked to the inland sea; environmental restrictions associated with the important local fishing grounds for sturgeon and the related production of caviar; deep, high-pressure targets (more than 5,000 meters); presence of high volumes of sulfur as in Tengiz and Astrakhan fields; geopolitics, etc. The extremely shallow water (no deeper than 4 meters) and ice coverage during part of the year demanded the construction of artificial islands with reinforced defense against moving ice. The huge costs would have to be offset by the potential scale, so size was the main driver of this extremely complex, technically daring adventure. No more data than the poor available seismic could be expected. The decision was therefore a pure gamble. It was recommended by the exploration management of Total and had to be approved at the highest level of the company because of the size of the investment and the strategic character of the project in a new country.
In the end the project was of such magnitude that Kazakhstan’s authorities decided to establish an operating joint company comprised of selected international oil companies, including Total, and the country’s national oil company, which held an interest in the venture. Some of these companies were delegated as operators for different phases of the project. The supergiant hunting party was successful; a multibillion-barrel field was found. Kashagan is currently producing 400,000 boepd and this may increase significantly after surmounting extreme difficulties regarding problems of sulfur-related corrosion.
Lesson: This prospect carried a huge seal risk (negative) but positive analogs for reservoir. An expected supergiant in case of success was by far the dominant driver, allowing acceptance of geological risk and a multitude of challenges of all sorts, including accepting political risk linked to the enclaved block’s situation in an inland sea.
For a summation of the critical factors in exploration decision-making, look to part 2 of this story in the Historical Highlights section of next month’s EXPLORER.