North Sea Chalk Completions- A Laboratory Study
- David E. Simon (Halliburton Services) | Gerald R. Coulter (Halliburton Services) | George King (Amoco Production Research Co.) | George Holman (Amoco Production Research Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 1982
- Document Type
- Journal Paper
- 2,531 - 2,536
- 1982. Society of Petroleum Engineers
- 5.8.7 Carbonate Reservoir, 5.3.4 Integration of geomechanics in models, 2.2.2 Perforating, 2.4.5 Gravel pack design & evaluation, 2 Well Completion, 5.2.1 Phase Behavior and PVT Measurements, 1.6 Drilling Operations, 2.5.2 Fracturing Materials (Fluids, Proppant), 2.4.3 Sand/Solids Control, 1.2.3 Rock properties, 5.2 Reservoir Fluid Dynamics, 1.6.9 Coring, Fishing, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.7.1 Completion Fluids, 1.14 Casing and Cementing, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc)
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Chalk flow into the wellbore and rapid production decline problems have been encountered in certain North Sea chalk areas. Casing collapse in chalk intervals also has been a problem. This paper discusses the general geology and formation characteristics of the North Sea chalk. Because sufficient representative core samples were lacking, we chose to correlate the formation properties of chalk with Dania quarry rock. Our correlation study showed Dania quarry rock is a suitable substitute. Laboratory tests on this rock to assess formation rock/fluid compatibilities included penetrometer, fracture flow capacities, relative permeability, as well as fluid flow tests under confining pressure and elevated temperature. The fluid flow tests indicate severe reduction in matrix permeability caused by collapse of the pore structure at grain-to-grain contact. This permeability reduction occurs rapidly when the confining load exceeds the rock strength. Some chalks were found extremely sensitive to aqueous fluids. Thus, well completions with hydrocarbon-base fluids are essential for preserving formation integrity. When drilling through sensitive chalks. an oil-base mud should be used; when fracturing, an oil-base fluid is suggested for placing 20/40-mesh sand at a minimum of 2.0-lbm/sq ft (9.77-kg/m2) concentration.
Chalk reservoir rock is an exploration objective in parts of the North Sea, but production problems are associated with it. Chalks are typically very soft, with high porosity, and often contain much of the OIP. However, they exhibit low to very low matrix permeability. Thus, most chalk reservoirs are only marginally profitable unless production can be improved. Problems encountered during completion of these reservoirs include formation solids production with oil flow into the wellbore, collapsed pipe, and rapid production decline with or without stimulation. Because of these problems, a research study was initiated to evaluate (1) effects of completion fluids on chalk stability, (2) pore and rock collapse when different fluids are used, and (3) completion fluids that will minimize chalk problems or at least delay their onset. First, we present an overview of North Sea chalk geology.
Geology of North Sea Chalk
Chalks were deposited across the entire North Sea basin during the Late Cretaceous Age. Between 1,300 and 4,600 ft (369 and 1402 m) of chalk was deposited within the Central graben during this time. Presently, these chalks are buried beneath 6,500 to 9,850 ft (1981 to 3002 m) of overburden. Atypically high porosity values (relative to most chalks) are present throughout the Central graben. Dania chalk porosities of as much as 40% are common. In the upper Maestrichtian, porosities are in the range from 20 to 30%, generally decreasing downsection. Chalk reservoirs are composed of coccoliths and coccolith fragments of grain sizes generally less than 20 microns (20 m). Fig. 1 is a typical scanning electron microscope (SEM) photomicrograph of a porous North Sea chalk. Upon deposition, chalk oozes have porosities of as much as 70%. However, with burial, their porosity decreases to 50% because of compaction, expulsion of some pore fluids, and formation of a grain-to-grain framework. Porosity is reduced further by pressure solution and reprecipitation of calcium carbonate cement. Porosities of less than 10% may be encountered at burial depths below 8,000 ft (2482 m) for normally pressured reservoirs.
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