Importance of Abnormal Formation Pressures (includes associated paper 6560 )
- W.H. Fertl (Dresser Atlas) | G.V. Chilingarian (U. of Southern California and Abadan Institute of Technology)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- April 1977
- Document Type
- Journal Paper
- 347 - 354
- 1977. Society of Petroleum Engineers
- 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 1.12.2 Logging While Drilling, 1.8 Formation Damage, 5.2 Reservoir Fluid Dynamics, 1.12.6 Drilling Data Management and Standards, 1.6 Drilling Operations, 1.5 Drill Bits, 4.3.4 Scale, 5.1.1 Exploration, Development, Structural Geology, 2.4.3 Sand/Solids Control, 4.3.1 Hydrates, 1.6.1 Drilling Operation Management, 5.8.2 Shale Gas, 5.6.1 Open hole/cased hole log analysis, 5.9.2 Geothermal Resources, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 1.11 Drilling Fluids and Materials, 1.1 Well Planning, 2 Well Completion, 2.1.7 Deepwater Completions Design, 4.1.5 Processing Equipment, 5.3.4 Integration of geomechanics in models, 1.2.5 Drilling vibration management, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 5.8.5 Oil Sand, Oil Shale, Bitumen, 4.2 Pipelines, Flowlines and Risers
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Abnormally high pressures occur worldwide informations as old as the Cambrian age. Better knowledge and the ability to locate and evaluate over pressured formations are critical in drilling operations, completion techniques, and development of exploratory and reservoir engineering concepts.
Detection and quantitative evaluation of overpressured formations are critical to exploration, drilling, and production operations involving hydrocarbon resources. Worldwide experience indicates a significant correlation between the presence and magnitude of formation pressures and the shale/sand ratio of sedimentary sections. Distribution of oil and gas is related to regional and local subsurface pressure and temperature environments. Knowledge of the expected pore pressure and fracture gradients is the basis for (1)efficiently drilling wells with correct mud weights, (2) properly engineered casing programs, and (3) proper completions that are effective and safe, and allow for killing the well without excessive formation damage. In reservoir engineering, formation pressures influence compressibility and the failure of reservoir rocks, and can be responsible for water influx from adjacent overpressured shale sections as an additional driving mechanism in hydrocarbon production.
Abnormally high pore-fluid pressures are encountered in formations ranging from the Cenozoic era (Pleistocene age) to as old as the Paleozoic era (Cambrian age). Such pressures may occur from a few hundred feet below the surface to depths exceeding 20,000 ft and can be present in shale/sand sequences and/or massive carbonate-evaporite sections.
Overburden pressure originates from the combined weight of the formation matrix (rock) and the fluids (water, oil, and gas) in the pore space overlying the formation of interest.
Generally, it is assumed that overburden pressure increases uniformly with depth. For example, average Tertiary formations on the U.S. Gulf Coast and elsewhere exert an overburden pressure gradient of 1.0 psi per foot of depth (4231 kg cm m ). This corresponds to a force exerted by a formation with an average bulk density of 2.31 gm/cc. Worldwide experience also indicates that the probable maximum overburden gradient in clastic rocks may be as high as 1.35 psi/ft (0.312 kg cm m ). Furthermore, field observations over the last few years have resulted in the concept of a varying (not constant) overburden gradient for fracture gradient predictions used in drilling and completion operations.
Hydrostatic pressure is caused by the weight of interstitial fluids and is equal to the vertical height of a fluid column times the unit weight of fluid. Size and shape of this fluid column have no effect on the magnitude of this pressure.
The hydrostatic pressure gradient is affected by the concentration of dissolved solids (salts) and gases in the fluid column and the magnitude of varying temperature gradients. An increase in dissolved solids (higher salt concentration) tends to increase the pressure gradient, whereas increasing amounts of gases in solution and higher temperatures would decrease the hydrostatic pressure gradient.
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