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This article focuses on interpretation of well test data from wells completed in naturally fractured reservoirs. Because of the presence of two distinct types of porous media, the assumption of homogeneous behavior is no longer valid in naturally fractured reservoirs. This article discusses two naturally fractured reservoir models, the physics governing fluid flow in these reservoirs and semilog and type curve analysis techniques for well tests in these reservoirs. Naturally fractured reservoirs are characterized by the presence of two distinct types of porous media: matrix and fracture. Because of the different fluid storage and conductivity characteristics of the matrix and fractures, these reservoirs often are called dual-porosity reservoirs.
This commentary has been prepared by the SPE Reservoir Advisory Committee (RAC) to provide high-level insights for the discussion on the potential consequences of long-term shut-ins on conventional and unconventional reservoirs. The RAC comprises 61 subject matter experts (SMEs) covering the domain of reservoir technical discipline. The views presented in the commentary are the opinions of the SMEs and do not constitute an official position of the SPE on the subject matter. From a completions, production, and facilities perspective, there are significant, and potentially devastating, effects for the long-term shut-ins of wells. Everything we leave in the well and the surface facilities will be subject to corrosion, deterioration, and other chemical/mechanical effects. Perforations and the well itself may become plugged and deformed and the pumps and bottomhole assemblies may be rendered dysfunctional due to the settlement of sand and other debris/contaminants. Moreover, scale buildup and wax and asphaltene precipitation in and around the wellbore are well-known potential problems during shut-ins. The oil and gas industry has a very long history of well surveillance, well maintenance, and well remediation--but as an induction, we have not had any circumstances on the scale of the current situation.
The widely developed karst caves and fractures in carbonate reservoirs result in strong spatial heterogeneity. Consequently, the parameters obtained from cores and numerical simulation are limited in their ability to reflect the production possibility of the entire reservoir. To solve this problem, this paper proposes a new method of economic prediction on the basis of expert library and oilfield databases. The method takes into account geological factors and the effect of production factors on the economic prediction. The key parameters used for the economic prediction of a carbonate reservoir include well spacing, oil production, and annual decline rate. These parameters are mainly from core experiments in the laboratory or from the numerical simulation of wells, but caves and fractures are dispersed throughout the carbonate reservoir.
The Merriam-Webster Dictionary defines simulate as assuming the appearance of without the reality. Simulation of petroleum reservoir performance refers to the construction and operation of a model whose behavior assumes the appearance of actual reservoir behavior. A model itself is either physical (for example, a laboratory sandpack) or mathematical. A mathematical model is a set of equations that, subject to certain assumptions, describes the physical processes active in the reservoir. Although the model itself obviously lacks the reality of the reservoir, the behavior of a valid model simulates--assumes the appearance of--the actual reservoir. The purpose of simulation is estimation of field performance (e.g., oil recovery) under one or more producing schemes. Whereas the field can be produced only once, at considerable expense, a model can be produced or run many times at low expense over a short period of time. Observation of model results that represent different producing conditions aids selection of an optimal set of producing conditions for the reservoir.
The neutron-porosity log first appeared in 1940. It consisted of an isotopic source, most often plutonium-beryllium, and a single detector. Many variations were produced exploiting both thermal and epithermal neutrons. In most of the early tools, neutrons were not detected directly. Instead, the tools counted gamma rays emitted when hydrogen and chlorine capture thermal neutrons.
Cementing is an essential part of the oil well and with deeper wells drilled, the performance of cement decides the life of the well even more critically. Cement undergoes many changes from the time it is mixed on the surface and pumped downhole and allowed to set. The varying temperature changes from surface to downhole along with the exothermic reaction of the setting cement creates a complex series of events which decides the fate of the well. With the advent of new technology and research cement performance has been improved several folds. An essential part of oil well drilling today, cement had a very humble beginning.
Summary We propose a novel method for estimating average fracture compressibility during flowback process and apply it to flowback data from 10 multifractured horizontal wells completed in Woodford (WF) and Meramec (MM) formations. We conduct complementary diagnostic flow-regime analyses and calculate by combining a flowing-material-balance (FMB) equation with pressure-normalized-rate (PNR)-decline analysis. Flowback data of these wells show up to 2 weeks of single-phase water production followed by hydrocarbon breakthrough. Plots of water-rate-normalized pressure and its derivative show pronounced unit slopes, suggesting boundary-dominated flow (BDF) of water in fractures during single-phase flow. Water PNR decline curves follow a harmonic trend during single-phase- and multiphase-flow periods. Ultimate water production from the forecasted harmonic trend gives an estimate of initial fracture volume. The estimates for these wells are verified by comparing them with the ones from the Aguilera (1999) type curves for natural fractures and experimental data. The results show that our estimates (4 to 22×10psi) are close to the lower limit of the values estimated by previous studies, which can be explained by the presence of proppants in hydraulic fractures.
Full-field models using unstructured grids can capture detailed geometric information such as fracture distribution. However, these are computationally expensive and often numerically unstable because of convergence issues. In the complete paper, the authors investigated embedded discrete fracture modeling (EDFM) using artificial intelligence (AI) to overcome challenges associated with unstructured modeling. It has been proved that EDFM enables flexible fracture geometry because the fracture domain is relatively independent of the matrix regions. EDFM has been widely accepted recently because of its simplicity and computational efficiency.
Wells in unconventional reservoirs can experience sharp rate declines in the early stage of production, especially when experiencing aggressive drawdown. One key factor affecting rate decline is rock sensitivity to increasing compressive stress. The complete paper describes and quantifies the stress-dependence of compaction and permeability for anisotropic rock matrices, natural fractures, and hydraulic fractures, based on comprehensive rock tests of a fractured tight reservoir. Laboratory data show that rock permeability can be reduced by 10 to 99% with increasing confining stress. Controlling factors include rock characteristics such as authigenic cementation, pore structure, clay content, natural fractures, and pore volume compressibility.
Composite materials can offer technologically viable and cost-effective solutions for the production of highly corrosive fluids in very deep water, although there is a need to access the key issues of durability and integrity assurance of these components. Research in this area seeks to address their safe use during the operating life of production systems. This paper gives an overview of ongoing research activities on the subject of offshore use of composite flowlines, risers, and topside piping. The operator developed a plan to deploy an instrumented composite drilling- riser joint in different positions along a drilling riser operating at a given platform. The idea was to submit the composite joint to different load levels--dependent on the position of the joint alongside the riser--and by doing so address its structural behavior in a real operational environment.