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A Surprise in the Colombian Foothills

This is the story of the drilling of a costly ($60 million) Lahee A-1 well in the Colombian foothills, which presented significant deviations from the prognosticated stratigraphy halfway to the objective – and became an operational nuisance.

Nonetheless, it is mainly a story of successful management and prompt response to the geological uncertainty.

Eventually the result was highly satisfactory, as the well:

  • Landed in the best position in a narrow structure.
  • Tested 7,000 b/d.
  • Has produced more than two mbbls of oil since it was completed in May 2009.

The XN1z well was designed to test a relatively small, undrilled fault block in the prolific Cusiana-Cupiagua trend, which is one of Colombia’s two most significant discoveries in the last 30 years.

The area of the well itself was part of the Santiago de las Atalayas license, in which Ecopetrol participated with 50 percent and its partners (BP, Total and Triton) held the remaining share. Ecopetrol did not share in the original exploration costs, but after the discovery, as per the original contract, exercised its right to participate in 50 percent of the production costs and benefits.

Most of the contract area reverted to Ecopetrol in June 2010.

When the operators decided to drill well XN1z they were mindful of this deadline, believing the well would pay for itself and return a profit before this date.

The well was spudded in September 2008 and it was supposed to be completed and producing by April 2009.

Things did not go as planned.

Well Plan

The XN1z well was planned to test and drain a fault block adjacent to the Cupiagua Sur Field. There were two 3-D seismic surveys of the structure and it was decided to plan the well using only the one with the most updated processing version (pre-stack depth migration, PSDM).

The initial well trajectory was “slightly” modified in the last stage of planning, given the requirements for a final vertical section for hydraulic fracturing.

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This is the story of the drilling of a costly ($60 million) Lahee A-1 well in the Colombian foothills, which presented significant deviations from the prognosticated stratigraphy halfway to the objective – and became an operational nuisance.

Nonetheless, it is mainly a story of successful management and prompt response to the geological uncertainty.

Eventually the result was highly satisfactory, as the well:

  • Landed in the best position in a narrow structure.
  • Tested 7,000 b/d.
  • Has produced more than two mbbls of oil since it was completed in May 2009.

The XN1z well was designed to test a relatively small, undrilled fault block in the prolific Cusiana-Cupiagua trend, which is one of Colombia’s two most significant discoveries in the last 30 years.

The area of the well itself was part of the Santiago de las Atalayas license, in which Ecopetrol participated with 50 percent and its partners (BP, Total and Triton) held the remaining share. Ecopetrol did not share in the original exploration costs, but after the discovery, as per the original contract, exercised its right to participate in 50 percent of the production costs and benefits.

Most of the contract area reverted to Ecopetrol in June 2010.

When the operators decided to drill well XN1z they were mindful of this deadline, believing the well would pay for itself and return a profit before this date.

The well was spudded in September 2008 and it was supposed to be completed and producing by April 2009.

Things did not go as planned.

Well Plan

The XN1z well was planned to test and drain a fault block adjacent to the Cupiagua Sur Field. There were two 3-D seismic surveys of the structure and it was decided to plan the well using only the one with the most updated processing version (pre-stack depth migration, PSDM).

The initial well trajectory was “slightly” modified in the last stage of planning, given the requirements for a final vertical section for hydraulic fracturing.

The well reached 14,900 feet after 130 days of drilling, which was still 1,200 feet (about 20 days) away from the target and about 1,700 feet (35 days) away from TD. At this point, the stratigraphy was different than predicted, leading to serious concerns about the location of the well relative to the target structure.

The problem was threefold:

  • There was a chance of missing the reservoir, which is always a bad thing, especially in costly wells.
  • Time pressure – This project had specific time limitations for the private partners, given that the producing license would expire less than one year after completion.
  • Operational - There were about 3,500 feet in the open-hole section, which implied well-stability issues.

Under these circumstances, the subsurface team had the task of evaluating the situation and recommending the way forward minimizing the business impact.

Building Scenarios

The first step was to understand the potential causes of the problem – and the most likely candidates were incorrect seismic velocities, mapping inaccuracy and incorrect spatial positioning of the seismic events.

Three potential scenarios were defined:

  • The first related to inaccurate time-to-depth conversion, picturing the target horizon to be shallower than its actual subsurface location.
  • The second considered that the mapped seismic reflection had been incorrectly tied and it actually corresponded to a shallower, non-prospective interval.
  • The third scenario was based on the possibility of an important lateral shift on the seismic, resulting in the well drilling in front of the structure.

Having three potential explanations for the XN1z situation was good progress, and the next task was validation.

A quick look at the seismic interval velocities ruled out scenario 1. Anomalous velocities were required to position the reservoir target much deeper than predicted.

The second scenario also was discarded after a fast-track seismic re-interpretation that tied the target horizon to the northwest and southeast well control points in the neighboring Cusiana and Cupiagua fields. This quick mapping exercise supported the presence of the reservoir in the XN1z structure.

During the validation of the third scenario a preliminary reprocessed version of the second existing 3-D seismic dataset became available. In this information, the XN1z structure showed a lateral shift of 300-400 meters with respect to the previous seismic versions, both in map and cross-sections.

According to the geophysicists, this was due to the anisotropy caused by the layered effect in the overburden wedge.

Unfortunately, in this very short time frame (the rig was waiting for instructions), it was difficult to rule out one of the two seismic data sets available, or to confidently say which one was positioning the geological features more correctly.

The review of the possible scenarios supported the lateral shift of the seismic reflections as the more probable explanation for the difference between the predicted and the drilled stratigraphy in the XN1z well.

Next task: Recommending what to do.

The first choice was to continue drilling up to the planned total depth, confirm the hypothesis, get additional information and plan a geological sidetrack. The second alternative was to stop drilling and make an early sidetrack.

The subsurface team concluded there was enough information to predict that, if continuing in the planned trajectory, the well would probably be landing off the structure – and that it was worth the risk of performing a sidetrack right away.

The next associated challenge was to define the subsurface target coordinates. This required reducing the seismic mapping uncertainty, which was done by remapping the seismic, tracking only the clear, continuous, strong reflection representing the reservoir in each data set, which increased the chances of reaching the reservoir in an optimum location.

This was accomplished by examining all the available seismic versions (time, depth, old and new).

A set of maps for the objective were produced and compared, and the overlapping area for all of them was used in defining the new target.

Stick to the Plan

Finally, it was time to communicate. The subsurface team clearly and openly discussed with the drilling and projects teams the technical support and the reasoning behind the early sidetrack alternative.

The plan also was presented to the upper management and the project partners, highlighting the remaining risks and uncertainties – and then, the sidetrack well started.

The upper half of the new section was done in 20 days, with a good match to the new prognosis. The stratigraphy in the lower section was, to some point, anomalous and created considerable doubts and tension in the multidisciplinary team and among the decision makers.

The subsurface team had to resist calls to stop drilling and re-design the sidetrack well, increasing the lateral displacement toward the flank of the structure.

The fundamental support to maintain the defined plan was the technical analysis and the consistent methodology used to reduce the uncertainty associated with the seismic data and the mapping.

After 30 days (about 4,400 feet) of drilling, the sidetrack well encountered a siltstone stratigraphic marker with partial correlation, 70 percent certainty of being 20-30 feet above the target level.

Because of the important mud losses experienced and a high risk of stuck pipe events, another difficult decision was made to run and cement the 9 5/8-inch liner.

The well finally, 15 days later, reached the reservoir in the oil leg, validating the third scenario postulated during the framing stage.

The integration of the new seismic mapping, with the drilling data and the structural dips, confirmed that the well landed in an optimal location. Consequently, production delays and reserves losses for private partners were avoided, the well tested 7,200 b/d, and the associated cost savings were estimated to be about US$7 million.


Several lessons were derived and applied after this experience, but probably the most important lesson to be used in similar situations, and for planning wells in complex geological settings, is:

Building several geological models that honor the available data, and consider that all of them may have significant probability of occurring.

We often hear about this and build more than one geological model, but we end up applying only our “best” interpretation to any situation and archiving the rest.

A base case is required for planning – but considering alternative scenarios ensures flexibility, contingencies and a better communication of the project’s uncertainties and risks.

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