Summary
Horizontal well targeting is often a greater challenge in massive, fractured carbonates than in low-productivity, poorly connected, and relatively thin reservoirs. This paper discusses methods to target horizontal wellbores in three-dimensional space to both confirm the fracture interpretation and establish high-efficiency oil capture. Several well examples are presented to illustrate the targeting objectives and the resulting well performance. Early in the program, the horizontal drilling objectives sought to maximize the lateral length in a direction determined by offset well productivity; the sample philosophy as is used in matrix-dominated reservoirs. Analysis of these results and employment of methods presented in this paper indicate profit can be maximized by drilling to a specific target to intersect a fracture trend at an optimum elevation instead of concentrating on maximizing length of lateral. Intervals of rapid penetration, lost circulation, and/or bit slides, along with cutting sample compositions, provided insight for confirmation and extension of the fracture network interpretation. The width of disturbance and degree of fracturing observed along interpreted fracture trends are valuable data for improved fracture network interpretation and computer simulation. Both the elevation and number of fracture branches encountered are significant strategic planning issues for oil recovery from unconfined oil columns in a massive carbonate system. Results from a large number of horizontals indicate significant productivity increases are achieved by proper targeting of laterals into major fracture features.
Introduction
Horizontal wells provide a unique assessment tool for formations containing reservoirs dominated by discontinuous flow features such as fractures or interbedded sandstones. Massive carbonate formations are the most extreme setting for large-scale, high-contrast, discontinuous reservoir properties. In sandstones of moderate to low quality, horizontals are typically applied to improve rate by exposing additional formation for fluid entry at high drawdown. In carbonates, horizontals serve to intersect high-conductivity flow features. In sandstones, high flow quality often coincides with sand accumulation. In contrast, carbonate flow is often highly discontinuous while storage capacity remains a relatively continuous function (as limited by depositional and diagenetic porosity history).
Since 1993, significant study has gone into identifying the extent and quality of fracture networks and the impact these systems have had on reservoir management, fluid reinjection, and completion efficiency.1,2 In west Texas alone, well over 100 short-radius horizontal wells have been drilled in one field since 1986. Horizontals drilled in this fractured carbonate reservoir were initially done to maximize oil production while limiting gas coning.3 With the recent fracture studies, emphasis has moved to using horizontal boreholes to connect with large flow features not penetrated in existing wellbores.4,5 These more recent wells have targeted fracture zones interpreted from flexure maps which are developed from a second derivative analysis of structural surface maps. This paper provides results of several horizontal wells drilled with the intent of cutting the interpreted fracture zones.
Targeting horizontal wells requires an understanding of massive carbonate features as well as discontinuous flow features. This paper will discuss how mapping was used to determine flow-feature locations; how horizontal drilling techniques were used to intersect these targeted flow features; and a discussion of the refinement of the interpretation and the drilling operations.
Massive Carbonate Flow Features
What is a massive carbonate? Carbonates that have relatively thick (100 ft or greater) intervals of mixed porous and tight/brittle rock types, free of continuous soft shale or anhydrite layers, are considered massive for this discussion. Structural deformation is subtle in many massive carbonate reservoirs, but still highly significant in generating preferential flow within the reservoir body. Minor deformation, as resulting from differential compaction and formation dip growth is accommodated in a range of extensional fracturing of the relatively brittle carbonates. Potential solution enhancement of fracture and fault zones further enhances flow. The highly conductive flow features of these carbonates often are a mix of bedding parallel (matrix) and subvertical (fracture) features.2 Data gathered from vertical wells can bias the interpretation of flow-feature population due to sampling a greater population of bedding parallel features. Vertical wells statistically encounter numerous short, mostly random-oriented fractures, but very few of the largest subvertical fracture features.
Horizontal wells, in contrast, encounter few bedding parallel flow features in exchange for a full range of subvertical fracture flow features. Horizontal wells can provide data for direct assessment of fracture frequency and matrix block size in contrast to the highly interpretive approach required for assessment from vertical well data. More importantly, horizontal well data provides insight into the lateral variance in subvertical fracture features. Significant variation is expected between low fracture intensity near the center of a large formation block relative to the high frequency expected near the edges of this block where strain is concentrated. Block edges for large-scale features may follow obvious faults, hingelines (linear trends of dip change), or structural noses. Fig. 1 conceptually illustrates a fractured rock mass with a horizontal well intersecting a strain zone of likely high-flow capacity. Often, the structural indications of block-edge strain zones are subtle and easily merged with interpreted depositional or erosional changes across the field. Here, horizontal well data are critical to generation of an adequate flow-feature model.
Horizontal Drilling: Regulatory and Contractual Implications
