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Hydraulic fracture geometry (i.e., critical results of length and proppant placement) is driven by four major in situ parameters: Fracture Height (H), Modulus (E), Fluid Loss (C), and "Apparent" Fracture Toughness (KI c-app ). In many (even most) cases, "Height" is the most important of these parameters – due to the need for some height confinement to achieve long fractures, or the need for height growth to insure good pay coverage. Due to this importance, industry research effort and most field measuring techniques concentrate on "Height." In particular, the growing use of seismic imaging is offering a tool to measure height growth away from the wellbore. Results from such diagnostics have often shown, as one expects, that in situ stress variations control height. However, results have also shown situations where this is apparently not the case. This paper examines another in situ parameter, "Layered Modulus," which also affects height. In addition, by controlling the "local" width of a fracture, layered modulus (i.e., layered formations with different layers having significantly different modulus) can have a critical effect on final proppant placement. The importance of layered modulus in directly controlling fracture height is illustrated in this paper, and this is compared with published solutions. In general, it is found that, just as concluded in the past, modulus contrast is probably not an important parameter in terms of direct control of fracture height. The greater importance lies in the effects on local fracture width. These local width changes can have a significant influence on controlling proppant placement – and this can be critical for low net pressure cases such as "water fracs" or fracturing in "soft" formations. It is also noted that layered modulus significantly impacts the average width of a fracture, and thus impacts the critical material balance aspects of fracture modeling if not properly accounted for. Finally, some of the theoretical solution problems created by "Layered Modulus" formations for fracture modeling are discussed and compared. This is done by comparing with 3–D Finite Element (static) solutions, and shows how some common industry "approximations" for layered modulus give incorrect results. Based on this, examples with a fracture propagation model using a finite element-generated stiffness matrix are used to define types of cases where a simple "average" modulus is acceptable, versus cases where more complex calculations are needed. Introduction Six major variables control hydraulic fracturing, fracture geometry, proppant placement, etc. Two of these are the "controllable" variables of fluid viscosity, µ, and pump rate, Q. The remaining four variables are "natural" variables and include:Height. Fracture height (or more generally fracture geometry) is possibly the most important unknown for fracture design and post-frac production success. Generally, it is recognized that in situ stress differences (the in situ stress profile) is the major controlling factor for this behavior. [1] At a minimum, in situ stress differences control the maximum fracture height, i.e., if the net pressure is not available to grow through high stress shale layers, then fracture height must be contained. The importance of fracture height/geometry is clear, and there are many research efforts and technical publications addressing this issue. [1–6]Fluid Loss. Fluid loss is typically characterized for hydraulic fracturing by a fluid loss coefficient, C, which characterizes linear flow fluid loss out of the fracture. This gives the familiar C/ (t-t) form of fluid loss behavior. Again, this variable has been exhaustively discussed in the literature including wall building characteristics of specific fluid systems, effects of natural fractures, behavior of fluid loss additives, etc. [7–16]

Summary Hydraulic fracturing has historically been a prime engineering tool for improving well producing rates, either by circumventing near-well damage or by stimulating well performance. This paper describes a somewhat new fracturing application where increasing rate was not the primary goal. In this case, the goal for fracturing was modification of the flow profile to allow a more uniform vertical production profile and thereby maximize sand-free rates over the perforated section of the reservoir. In best cases for such applications, this technique allows perforating of "weak" rock to be skipped, reduces risks of sand production, and allows greater wellbore drawdown through perforated intervals in more competent reservoir rock. This allows better long-term productivity and improved recovery and total project economics. In short, it was hoped that propped fractures would improve reservoir management of the Etive/ Rannoch formations in the Gullfaks field. Introduction The Gullfaks field, in the central part of the East Shetland basin in the northern North Sea, is operated by Statoil. The field was developed with three platforms and started production in Dec. 1986. Of more than 116 planned wells, 81 wells (including 6 subsea satellite wells) have been drilled. The field currently can produce about 600,000 BOPD, and estimated production life of the field is 20 years. The main drive mechanism is water injection. Predicted ultimate oil production from the field is 1,590 million bbl. About 465 million bbl was produced by Nov. 1993. Forecasted ultimate production represents 46% field recovery. Oil is produced from three major sandstone units: the Brent group, the Cook formation, and the Statfjord formation. The Etive/Rannoch formations of the Lower Brent group contain about 33% of mapped HCPV for the field. The reservoirs are overpressured, with an initial reservoir pressure of 4,495 psi at datum depth (6,070 ft below mean sea level) and 158°F. The shallow, highly porous sands are generally poorly consolidated. The oil is undersaturated, with a saturation pressure of about 3,550 psi, depending on formation depth and location.

Summary This paper provides a quick method to determine subsidence, compaction, and in-situ stress induced by pore-pressure change. The method is useful for a reservoir whose Young's modulus is less than 20% or greater than 150% of the Young's modulus of the surrounding formation (where the conventional uniaxial strain assumption may not hold). In this work, a parameter study was conducted to find groups of parameters controlling the in-situ stress, subsidence, and compaction. These parameter groups were used to analyze the numerical calculation results generated by a three-dimensional (3D), general, nonlinear, finite-element model (FEM). The procedure and a set of figures showing how to calculate the in-situ stress, subsidence, and compaction induced by pore-pressure changes are provided. Example problems are also included to prevent confusion on sign convention and units. This work showed that Geertsma's results, which are based on no modulus contrast between cap and reservoir rocks, should be extended to simulate more closely "real" reservoirs, which generally have distinct property differences between the cap and reservoir rocks. Highly porous and high-pressure North Sea reservoirs and tight sand formations surrounded by soft shale often fall into this category. The application is intended for sand-production control, casing buckling problems, design of hydraulic fracturing jobs, subsidence, and estimation of PV and formation damage resulting from permeability reduction during hydrocarbon production. Introduction The in-situ stress induced by pore-pressure change usually has been calculated on the assumption that a rock deforms uniaxially without inducing strain along the horizontal direction. The amount of subsidence was calculated by Geertsma, with the strain nuclei method. These calculations assume that a reservoir is thin, that its depth is reasonably great, and that its rigidity is close to that of the confining formation. However, statistics of field measurements has shown that many hydrocarbon reservoirs are thick or shallow or have elastic moduli that are significantly different from those of confining formations. For example, North Sea reservoirs often have static Young's moduli that are orders of magnitude smaller than those of the surrounding rocks before they are compacted because of hydrocarbon production, although the dynamic Young's modulus calculated from sonic logs may give only three to six times modulus contrast. Some tight formations in the U.S. also have rock several times more rigid than surrounding shale. When a hydraulic fracture, a sand-control process. a subsidence-control operation, or an evaluation of formation damage resulting from permeability reduction is conducted in such a reservoir, accurate information on the in-situ stress, reservoir compaction, or subsidence induced by pore-pressure changes helps in designing such operations. This work does not use or develop new mathematical techniques, but emphasizes two important issues. First, the common practice in the oil industry is to calculate PV compressibility, reservoir compaction, and in-situ stress change on the basis of reservoir-rock property data. However, this work emphasizes that some reservoirs also require the caprock property data to evaluate these quantities. Second, a quick method to evaluate PV compressibility, reservoir compaction, in-situ stress change, and subsidence has not been published previously. Although techniques to calculate these values are available, they require long times to run sophisticated simulation models. The purpose of this work is to provide a method for quick estimation of in-situ stress, compaction, and subsidence for a reservoir having simple geometry. A quick estimation of these values is often sufficient during the reservoir development stage because accurate reservoir descriptions are not available. Such a crude estimation is essential because the decisions on downhole and surface facility designs are made during the early stages of reservoir development. After more accurate reservoir descriptions are collected, however, we recommend that the 3D FEM be used for this work to get a better evaluation. The model can handle various complex problems, such as multilayer problems with heterogeneous rock properties, inclined reservoirs, irregular reservoirs, nonuniform pore pressure, nonlinear properties of rock, hysteresis effect of cyclic loading, and nonuniform reservoir pressure. Assumptions and Calculation Methods The in-situ stress is decomposed into two parts-original in-situ stress and-in-situ stress induced by pore-pressure change. ................................ (1a) and ............................ (1b) where K is the stress-ratio coefficient affected by rock grain shape, grain-size distribution, sedimentation process, present Poisson's ratio, tectonic force, temperature, and pore pressure. Delta sigma and delta sigma are in-situ stress components induced by pore-pressure change. If the pore-pressure change occurs over several years, we can reasonably assume that rock deforms elastically during the period. In addition, if the pore-pressure change is reasonably small and the state of stress is not far from hydrostatic-i.e., a small deviatoric stress-then a linear elastic deformation is a good approximation. Hence, a linear elastic deformation is assumed in this work for the calculation of delta sigma and delta sigma induced by the pore-pressure change. A disk-shaped reservoir is assumed for the present calculation as shown in Fig. 1. Although the moduli of the reservoir and the surrounding formation may vary within each formation, uniform moduli are assumed within both structures, respectively. The reservoir is located at depth D below the surface and its radius and height are r and h, respectively. More complex reservoir geometries require that data be entered directly into the 3D FEM used for the present calculations. Fig. 2 shows the finite-element meshes used for this work. The upper surface is free from a traction force, and the bottom surface is fixed to the rigid base rock. Infinite elements were used for the outer boundary. The hatched section is the reservoir and has elastic moduli different from those of surrounding formations. The pore pressure of the reservoir section is reduced to calculate the deformations and stress change of the reservoir and surrounding formations. Test runs were conducted for a well with and without a casing cemented to the borehole. JPT P. 9^

SPE and IADC Members Abstract A successful reinjection of oil-wet drill cuttings has been performed on the Norwegian Gullfaks Field. The reinjection was carried out in the annulus between two casing strings through a wear-protected wellhead. An effective way of grinding cuttings and mixing slurry by use of a new patent pending method known as SMACCC - Statoil Method for Autogenous Crushing and Classifying of Cuttings has been developed. The paper discusses reservoir aspects and presents simulated fracture geometries as a result of rock mechanical and slurry in-put property data. Further, the paper describes a 1000 hour wear test, involved equipment, and gives a derived formula describing wear from sand slurries on internal wellhead components. Introduction The basic background to the cuttings reinjection project wasStatoil's environmental policy to cause the least possible pollution of the environment, andthe company's policy to develop technologies and concepts meeting low crude prices. The increasing demand for highly deviated and longer wells currently necessitates the use of oil-based mud, which is neither permitted to be discharged into the sea nor to be burned. With newly realized environmental concerns, about disposal problems for drill cuttings and drilling solids residue for oil based mud systems, several new disposal methods are currently being considered and investigated by the oil industry. Since 1988, Statoil has reduced the use of oil-based mud by about 95% on the Gullfaks Field. The project of reinjecting cuttings, waste mud and oily waste water from drilling was a following-up project to virtually eliminate the discharge of oily waste from Statoil's drilling and production platforms. As of November 1st 1992, a total of 6500 Sm (40880 BBL) of waste drilling fluids and cuttings have been reinjected into shallow formations on the Gullfaks Field. Reinjection of cuttings by use of the new crushing and mixing system is now planned on several Statoil platforms in the North Sea. This paper discusses simulated reservoir and rock mechanical data together with fluid/slurry properties in conjunction with down-holedisposal operations describes a 1000-hour combined wellhead and centrifugal pump sand erosion test. An equation relating erosion to velocity and sand concentration is given. describes the size and capacity of the new SMACCC system, including an improved and wear-resistant centrifugal pump presents actual field test data and performance analyses for offshore disposal operations RESERVOIR MODELLING AND SIMULATION RESULTS General Considerations Subsurface injection is a world wide common method of waste disposal, and many injection wells have been operating for years with massive volumes of material being injected. The major difference between such "normal" disposal operations and disposal of drilling cuttings and impure mud is the high percentage of solids to be injected, with the corresponding requirement for injection above fracture closure pressure - e.g. it will be necessary to open and probably extend hydraulic fractures and/or open and extend existing natural fractures. P. 773^