Case History: Integration of Rock Mechanics, Structural Interpretation and Drilling Performance to Achieve Optimum Horizontal Well Planning in the Llanos Basin, Colombia, South America
Authors: Last N.C. , Lopez J.D. , Markley M.E. 
Published: December 2007

Case History: Integration of Rock Mechanics, Structural Interpretation and Drilling Performance to Achieve Optimum Horizontal Well Planning in the Llanos Basin, Colombia, South America.

The productivity enhancement associated with horizontal wells through reservoir intervals makes them an attractive option for improving overall field economics. However, the implementation of a first well of this type in an area requires careful planning if operational and commercial success is to be ensured, particularly if there are known geological and/or drilling difficulties. This paper describes the approach taken by ECOPETROL, the Colombian State Oil Company, to optimise the planning of the first horizontal well in the Llanos Basin, in a field some 50 km East of the tectonically active Eastern Cordillera of the Andes in Colombia, South America.

Introduction

ECOPETROL were planning to drill a horizontal well in the APIAY Field of the Llanos Basin in Colombia (Fig. 1). The well, GUATIQUIA 3H (G-3H), is needed to drain the reservoir sands in a structure trending approximately N20E in an area (Fig. 2) where there was no previous experience of drilling high angle or horizontal wells. Examining all aspects of the challenge associated with completing this well was essential if operational and commercial success was to be ensured. Recent experience has shown how difficult drilling in the nearby foothills can be, even in vertical wells. Hole instability there has been severe, and in general horizontal holes pose additional risk. Given the similarity of the rocks in the APlAY area, the troubles encountered in drilling the off-set vertical wells, and the potential similarity in the stresses, there had been conjecture that G-3H could not be drilled. With this background. ECOPETROL decided to commission an assessment of the rock mechanical and hole stability issues that were likely to impact the drilling of the well.

From a reservoir management point of view, the direction and length of a horizontal section through the pay zone will usually be selected on the basis of optimising overall reservoir performance. This will include considerations' such as the geometry of the structure, maximum drainage area and potential interference with the drainage pattern of other wells. These are clearly very important issues which directly impact the economic assessment of the well. Indeed, based on reservoir simulation and the proximity to existing surface infra-structure. the early conceptual designs had the proposed G-3H well being drilled from the south along the crest of the structure (N20E). However, integration of reservoir engineering considerations with potential drilling and completion difficulties may prompt the need to compromise to reduce overall operational risk.

Wellbore Stability Considerations

Wellbore instability can lead to drilling difficulties such as lost circulation where tensile rock failure has occurred to spalling and/or hole closure in the case of compressive rock failure. In severe cases hole instability can lead to stuck pipe and eventually loss of the open hole section. Conventional wellbore stability theory shows there are many factors that are likely to influence the competency of the wellbore wall, including formation pressure, depth, formation strength, stress state, mud weight, mud cake efficiency and time. Furthermore, the theoretical impact of well trajectory with respect to stress orientation is well understood, and demonstrates the need to carefully consider the well trajectory when planning high angle or horizontal well sections.

Formations are generally subjected to stresses derived from the weight of the overburden rocks, and any regional tectonic loading that exists. The stresses can be resolved into three principal components. which in most cases are the vertical, minimum horizontal and maximum horizontal stresses (Fig. 3). In passive sedimentary basins such as the North Sea the vertical stress is usually considered to be the largest (Fig. 3a).

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