Wayne Narr

Estimating Average Fracture Spacing in Subsurface Rock

Knowledge of the spacing of fractures in reservoir rocks (i.e., the distance between parallel fractures in a subsurface joint set) can lead to a better understanding of the production characteristics of a reservoir and serve to quantify the relative degree of deformation in subsurface rocks. In this paper, I present a new method for estimating the spacing of subsurface fractures; this new method is easy to use from the standpoint of both data collection and data analysis. The average fracture spacing method can be applied with boreholes of any orientation relative to a fracture set. The method is especially powerful when it is used for the relatively common case of a borehole nearly parallel to a fracture set (e.g., vertical borehole intersecting vertical fractures). Average fracture spacing is estimated from an analytical solution based on observed borehole-fracture intersections and observed fracture porosity; the only data required are the dimensions of the core (or imaged borehole) and the total height of all sampled fractures. Because the likelihood of intersecting fractures increases when a well is deviated perpendicular to the fractures of a set, fracture reservoirs commonly are candidates for deviated boreholes. An informed decision on borehole deviation requires predicting the fracture intersection frequency as a function of both deviation magnitude and direction. A new method, based on probabilities of borehole-fracture intersections, uses spacing and height data from subsurface joint-like fractures and the borehole diameter to predict fracture intersection frequencies for all possible well deviations. Fracture intersection frequency solutions are presented with respect to a conventional geographic reference frame, thus simplifying even the most complex three-dimentional situations.

Origin of Fracture Porosity--Example from Altamont Field, Utah

The occurrence of natural fracture systems in subsurface rock can be predicted if careful evaluation is made of the geologic processes that affect sedimentary strata during their cycle of burial, diagenesis, uplift, and erosional unloading. Variations in the state of stress within rock arise, for example, from changes in temperature, pore pressure, weight of overburden, or tectonic loading. Hence geologic processes acting on a sedimentary unit should be analyzed for their several contributions to the state of stress, and this information used to compute a stress history. From this stress history, predictions may be made as to when in the burial cycle to expect fracture (joint) formation, what type of fractures (extension or shear) may occur, and which geologic factors are most favorable to development of fractures. A stress history is computed for strata of the naturally fractured Altamont oil field in Utahs Uinta basin. Calculations suggest that fractures formed in extension, that the well-cemented rocks are those most likely to be fractured, that fractures began to develop only after strata were buried to great depth, and that the fracture system continued to develop as strata were uplifted and denuded of overburden. Geologic evidence on fracture genesis and development is in accord with the stress history prediction. Stress history can be useful in evaluating a sedimentary basin for naturally fractured reservoir exploration plays.

Origin of Reservoir Fractures in Little Knife Field, North Dakota

Thin, vertical, planar fractures observed in the Mission Canyon Formation, at the Little Knife field, are naturally occurring and appear to be extension fractures. The predominant east-west trend of the fractures, measured in oriented core from six wells, parallels the contemporary maximum horizontal compressive stress in the Williston basin. The fractures occur only in carbonate units, but within the carbonates their occurrence is not lithology dependent. Fracture density measured in cores of the reservoir carbonates averages 1 ft (.3 m) of fracture per 2.3 ft (.7 m) of core. The formation and mineralization of reservoir fractures were the most recent diagenetic events in the Mission Canyon Formation at Little Knife. Study of aqueous and hydrocarbon fluid inclusions associated with the fractures reveals: (1) fractures formed after the strata were buried to at least their present depth of 9,800 ft (2,987 m), which indicates their age is post-Mesozoic; (2) the pore-fluid pressure gradient was normal hydrostatic immediately after, if not during, fracture system development; (3) formation-water salinity has remained fairly constant since fracture initiation; (4) migration of hydrocarbons into the reservoir probably preceded fracture genesis; and (5) methane concentration may have decreased since fracture initiation.

Modeling Fluid Flow in Complex Naturally Fractured Reservoirs

We use a new numerical code to calculate single phase fluid flow in naturally fractured reservoirs. Our code is unique in that it can handle both complex fracture patterns and the coupling of the matrix and fracture flow fields. Our results show that details of the fracture statistics can become less important as the matrix becomes more permeable. We also find that the coupling of the matrix and fracture flow fields is very strong. We demonstrate the application of our code to develop grid block permeability values for use in continuum reservoir simulators. Mapping subsurface fracture distributions for use in our code is a key challenge. We briefly present the results of a new methodology that uses physical models and geostatistical techniques to generate such data.

Reservoir Modeling To Characterize Dual Porosity, Tengiz Field, Republic Of Kazakhstan

Tengiz Field is the world’s deepest developed supergiant oil field, with an oil column height of nearly 1600 meters. The reservoir consists of Devonian and Carboniferous platform/slope carbonates, divided into three stratigraphically-defined producing units. Production of more than 500,000 BOPD is mainly from the upper unit. A significant portion of this production is controlled by natural fractures. A new reservoir model has been constructed to support a future growth project, including miscible gas injection, and to provide input to reservoir management strategies, development planning, and oil-in-place estimation.

Origin of Reservoir Fractures in Little Knife Field, North Dakota: ABSTRACT

End_Page 611------------------------------Thin, vertical, planar fractures in the Mission Canyon Formation of the Little Knife field, in west-central North Dakota, appear to be naturally occurring extension fractures. The fractures are restricted to carbonate units, but are not lithology dependent within the carbonate rocks. Fracture density averages 1 ft (0.3 m) of fracture per 2.3 ft (0.7 m) of core. The predominant east-west trend of the fractures, measured in oriented core from six wells, parallels the estimated maximum horizontal compressive stress in the Williston basin. Figure Formation and mineralization of these fractures were the most recent diagenetic events in the Little Knife carbonates. Heating-and cooling-stage observations of fluid inclusions in crystals bridging the fractures yield homogenization temperature ranges of 90 to 106°C and 102 to 126°C for hydrocarbon and aqueous inclusions, respectively. Correlation of these observations with the PVT properties of Little Knife reservoir fluids leads to the following conclusions: (1) the fractures formed after the strata were buried to at least their present depth of 9,800 ft (3,000 m), which indicates their age is post-Mesozoic; (2) the pore-fluid pressure gradient was normal hydrostatic immediately after, if not during, fracture system development; (3) formation-water salinity has remained f irly constant since fracture initiation; (4) migration of hydrocarbons into the reservoir probably preceded or accompanied fracture genesis; and (5) methane concentration may have decreased since fracture initiation. The geologic mechanism specifically responsible for creating the fractures remains unknown. The potential for using fluid inclusions to document changing methane concentration within a reservoir could be significant to studies of hydrocarbon migration. End_of_Article - Last_Page 612------------

Origin of Subsurface Fracture Systems--Example from Altamont Field, Uinta Basin, Utah: ABSTRACT

The Altamont field is a major, naturally fractured, overpressured oil reservoir situated on the gently northward-dipping flank of the asymmetric Uinta basin. Low porosity Tertiary clastic and carbonate rocks form a stratigraphic trap beneath thick Green River Formation carbonate mudstones. The reservoir occurs at depths between 2,450 and 5,200 m, and thickness of the producing interval commonly exceeds 700 m. Permeability is derived mainly from vertical fractures in sandstones and carbonate rocks. Joints in surface rocks within the basin occur predominantly as orthogonal sets whose orientations correlate with major tectonic features bordering the basin. Fractures in oriented core of reservoir rock exhibit a single dominant north-northwest trend. Rock mechanics tests on samples from the core indicate anisotropy coincident with the trend of microcracks. Timing of subsurface fracture development relative to basin subsidence and uplift is interpreted from fluid-inclusion thermometry conducted on quartz and carbonate crystals which line open fractures. Results indicate that fractures opened when strata were near their maximum burial depth. The fracture system became more extensively developed as uplift and erosional unloading continued. Various geologic processes interact during the burial, diagenetic, tectonic, and unloading history of rocks in a sedimentary basin. Their combined effect determines the state-of-stress in stratigraphic units. At Altamont the effect of overpressuring has been critical in fracture genesis. Thorough evaluation of the relative influence of individual geologic processes on the stress history of rock units in a basin can be usefully applied in exploration for fracture reservoirs. End_of_Article - Last_Page 755------------