Drillstem/well testing

In designing a UBD circulation system, the bottomhole pressure must be maintained below the reservoir pressure. The surface separation system must have sufficient capacity to handle the flow rates and pressures expected while drilling. The surface separation system must be capable of handling sudden productivity increases from the well from fractures or flush zones and retain the ability to "choke" back production if well outflow is more than what can be handled safely by the surface separation equipment. The separation system must also be able to work within the design parameters of the well. The BHP must be less than the static reservoir pressure under static and dynamic conditions to enable reservoir fluid inflow into the wellbore.

The definition of a tight gas reservoir is one that must be successfully fracture treated to produce economic volumes of gas at economic flow rates. In this page, we will discuss a few basic considerations for fracture treatment design and application. Many tight gas reservoirs are thick, layered systems that must be hydraulically fracture treated to produce at commercial gas flow rates. To optimize the completion, it is necessary to understand the mechanical properties of all the layers above, within, and below the gas pay intervals. Basic rock properties such as in-situ stress, Young's modulus and Poisson's ratio are needed to design a fracture treatment. The in-situ stress of each rock layer affects how much pressure is required to create and propagate a fracture within the layer. The values of Young's modulus relate to the stiffness of the rock and help determine the width of the hydraulic fracture.

The definition of a tight gas reservoir is one that must be successfully fracture treated to produce economic volumes of gas at economic flow rates. In this page, we will discuss a few basic considerations for fracture treatment design and application. Many tight gas reservoirs are thick, layered systems that must be hydraulically fracture treated to produce at commercial gas flow rates. To optimize the completion, it is necessary to understand the mechanical properties of all the layers above, within, and below the gas pay intervals. Basic rock properties such as in-situ stress, Young's modulus and Poisson's ratio are needed to design a fracture treatment. The in-situ stress of each rock layer affects how much pressure is required to create and propagate a fracture within the layer. The values of Young's modulus relate to the stiffness of the rock and help determine the width of the hydraulic fracture.

Type curves provide a powerful method for analyzing pressure drawdown (flow) and buildup tests. Fundamentally, type curves are preplotted solutions to the flow equations, such as the diffusivity equation, for selected types of formations and selected initial and boundary conditions. Because of the way they are plotted (usually on logarithmic coordinates), it is convenient to compare actual field data plotted on the same coordinates to the type curves. The results of this comparison frequently include qualitative and quantitative descriptions of the formation and completion properties of the tested well. The solutions plotted on type curves are usually presented in terms of dimensionless variables.

Type curves provide a powerful method for analyzing pressure drawdown (flow) and buildup tests. Fundamentally, type curves are preplotted solutions to the flow equations, such as the diffusivity equation, for selected types of formations and selected initial and boundary conditions. Because of the way they are plotted (usually on logarithmic coordinates), it is convenient to compare actual field data plotted on the same coordinates to the type curves. The results of this comparison frequently include qualitative and quantitative descriptions of the formation and completion properties of the tested well. The solutions plotted on type curves are usually presented in terms of dimensionless variables.

The generic term "intelligent well" is used to signify that some degree of direct monitoring and/or remote control equipment is installed within the well completion. Until the late 1980s, remote monitoring was generally limited to surface pressure transducers around the tree and surface choke, with remote completion control restricted to the hydraulic control of safety valves and (electro-) hydraulic control of tree valves. The first computer-assisted operations optimized gas lifted production by remote control near the tree and assisted with pumping well monitoring and control. Permanent downhole pressure and temperature gauges are commonly run as part of the completion system and combined with data transmission infrastructure. With the development, successful implementation, and improving reliability of a variety of permanently installed sensors, it was perceived that the potential to exercise direct control of inflow to the wellbore would provide significant and increased economic benefit.

The generic term "intelligent well" is used to signify that some degree of direct monitoring and/or remote control equipment is installed within the well completion. Until the late 1980s, remote monitoring was generally limited to surface pressure transducers around the tree and surface choke, with remote completion control restricted to the hydraulic control of safety valves and (electro-) hydraulic control of tree valves. The first computer-assisted operations optimized gas lifted production by remote control near the tree and assisted with pumping well monitoring and control. Permanent downhole pressure and temperature gauges are commonly run as part of the completion system and combined with data transmission infrastructure. With the development, successful implementation, and improving reliability of a variety of permanently installed sensors, it was perceived that the potential to exercise direct control of inflow to the wellbore would provide significant and increased economic benefit.

The generic term "intelligent well" is used to signify that some degree of direct monitoring and/or remote control equipment is installed within the well completion. Until the late 1980s, remote monitoring was generally limited to surface pressure transducers around the tree and surface choke, with remote completion control restricted to the hydraulic control of safety valves and (electro-) hydraulic control of tree valves. The first computer-assisted operations optimized gas lifted production by remote control near the tree and assisted with pumping well monitoring and control. Permanent downhole pressure and temperature gauges are commonly run as part of the completion system and combined with data transmission infrastructure. With the development, successful implementation, and improving reliability of a variety of permanently installed sensors, it was perceived that the potential to exercise direct control of inflow to the wellbore would provide significant and increased economic benefit.

The generic term "intelligent well" is used to signify that some degree of direct monitoring and/or remote control equipment is installed within the well completion. Until the late 1980s, remote monitoring was generally limited to surface pressure transducers around the tree and surface choke, with remote completion control restricted to the hydraulic control of safety valves and (electro-) hydraulic control of tree valves. The first computer-assisted operations optimized gas lifted production by remote control near the tree and assisted with pumping well monitoring and control. Permanent downhole pressure and temperature gauges are commonly run as part of the completion system and combined with data transmission infrastructure. With the development, successful implementation, and improving reliability of a variety of permanently installed sensors, it was perceived that the potential to exercise direct control of inflow to the wellbore would provide significant and increased economic benefit.

There are two fundamental problems that make accurately estimating the productivity of a horizontal well more difficult than estimating the productivity of a vertical well. The theoretical models available have a number of simplifying assumptions and the data required for even these simplified models are not likely to be available. Still, we must make estimates and decisions based on those estimates. In this page, two productivity models that have proved useful in practice are discussed. The first, published by Babu and Odeh[1] in 1989, is limited to single-horizontal wells.