The formation integrity test (FIT) is one of three types of formation strength tests, and it is used to evaluate the strength and integrity of a newly drilled section of well formation. After setting a section of casing and drilling out the casing shoe, several feet of new formation is drilled and the formation is gradually pressurized to a pre-determined pressure and then held during a subsequent shut-in stage. The FIT data is analyzed to verify the bonding strength of the cement around the casing shoe and to determine the maximum mud weight that can be used to drill the next well section. This test is essential to ensure that the formation can withstand the pressures it will encounter during drilling and production operations and to avoid loss of well control.
The integrity of a wellbore changes with every drilled foot of depth, and mud weight is the sole pressure mechanism keeping the borehole stable. Formation Integrity Testing is vital for maintaining well integrity as it helps to prevent well control issues, such as blowouts and other hazardous events. In addition to verifying the maximum mud weight needed to drill the next well section, a FIT is used to compute the minimum mud weight required to prevent hole collapse and to evaluate the quality of the cement bond around the casing shoe. By verifying the formation’s ability to hold pressure, avoiding hole collapse, and assuring cement integrity, operators can substantially improve the safety and efficiency of drilling operations.
Essential safety measures during FIT include:
After the casing or liner is cemented and before drilling out the cement at the shoe, a casing integrity test (CIT) is typically run to ensure the integrity of the casing or liner. During the CIT, drilling fluid is pumped into the casing or liner. The shut-in valve is closed when the target pressure is reached (below the maximum allowable pressure). If the pressure analysis passes specific criteria, the CIT is successful.
FIT guidelines are established to ensure that a valid test is conducted. The following guidelines below are used for reference during the test and subsequent FIT analysis.
The standard FIT, the Leak-Off Test, and Extended Leak-Off Test are commonly known as formation strength tests. The different uses and procedures for these tests are described below.
A standard formation integrity test involves gradually increasing the bottom hole pressure to a predetermined level to check the formation’s ability to withstand the pressure without leaking off drilling mud. Following a successful casing integrity test, FITs are generally performed using the following steps:
A Leak-Off Test (LOT) is performed to determine the exact pressure at which the formation begins to fracture. It is often conducted at various depths during the drilling process to assess the formation’s pressure containment capacity. The key difference between the LOT and standard FIT is that the LOT involves a controlled increase in pressure until a small amount of fluid leaks into the formation, indicating the fracture point. This information is valuable for more accurately estimating formation stresses, which can be used to optimize the number of casing strings required.
For a typical LOT, pressurization is continued past the LP until the wellbore pressure induces a stable fracture in the formation (fracture Initiation pressure). When the crack opens, fluid is lost to the formation across the permeable faces of the fracture. These fluid losses lead to smaller increases in pressure as additional fluid is pumped, which is indicated by the change in slope of the plot at a point called the fracture initiation pressure (FIP). The rising pump pressure at the surface up to the pump stop pressure (PSP) indicates stable fracture growth, as fluid is lost along the length of the fracture. After PSP, the fracture becomes unstable at a point called the unstable fracture pressure (UFP) because the fracture is extended away from the wellbore. When the pressure begins to asymptotically level off at the fracture propagation pressure (FPP), the test is concluded. Drilling operations then typically resume if the tests results permit the use of a suitable mud weight and if no cement channels are detected.
The XLOT is a series of LOTs that may be run to obtain horizontal stress data for predicting wellbore stability. The XLOT is a longer and more comprehensive test in which the mud continues to be pumped after the FIP is reached to determine the fracture closure pressure. Chronologically, the XLOT process consists of the following stages:
This process can be repeated multiple times to open and propagate the fracture to gather more data. The figure below shows an XLOT with a repeating cycle.
The results of a FIT are typically analyzed by visually interpreting pressure vs. time and pressure vs. volume plots or comparing them with theoretical models of formation behavior under stress. Key indicators of well integrity from FIT results include:
To accurately analyze LOTs and XLOTs, multiple factors should be considered, such as formation permeability, fluid compressibility, stresses around the wellbore, and mud type.
The following factors can distort FIT, LOT, and XLOT results and lead to interpretation difficulties.
Although the LOP is defined as the point where the trend of the pressure increase deviates from linearity, the pressure-volume trend prior to initiating a fracture can sometimes be non-linear. Factors such as air in the system or seepage caused by permeability in the formation can produce a non-linear pressurization response.
Incorrect identification of FIP, also known as the leak-off pressure (LOP), can lead to a variety of problems and/or unnecessary expenses for a well. For example, if a lower than expected LOP is interpreted as a cement channel, the operator may conduct a squeeze job in an attempt to increase the LOP. However, if the low LOP is caused by a lower-than-expected fracture gradient, the operator will have wasted time and money on the squeeze job. Conversely, if a lower than expected LOP is interpreted as a low fracture gradient, when it is really caused by a cement channel, the operator may use an incorrect low value as an upper limit for mud weights. This could lead to prematurely setting the next string of casing or to choosing a dangerously low mud weight, which may not be able to control the well. Finally, if a LOP is misinterpreted to be higher than the actual LOP, an operator may use an excessive mud weight, which could lead to lost circulation problems.
The effect of drilling fluid properties can induce inaccuracies in the interpretation of surface-collected data, resulting in a higher pressure than the correct value.
FIT analysis is often performed by “eyeballing” the pressure curve to determine whether the test is successful. Subjective analysis introduces human error and inconsistent interpretation of test results.
Higher pump rates result in higher values for FIP and FPP. Since these pressures are recorded from gauges at the surface, higher pump rates result in higher pump friction which causes higher observed FIP and FPP values. These higher pressures are not an indication of formation strength. Therefore, it is suggested that LOTs be performed at the lowest possible pump rate.
Deepwater HPHT wells have a lot of uncertainty regarding the integrity of the wellbore. These wells often experience significant deviations from the planned conditions. They can encounter very high levels of overpressure, intense heat, and formation pressures that are close to the point where formations can fracture.
To minimize measurement distortions and improve the accuracy of FITs, LOTs and XLOTs, several best practices should be followed:
Recent advancements in FIT technology include the development of more accurate and reliable pressure measurement devices, real-time data monitoring systems, and improved software tools for pre-test planning, test execution and analysis.
Recent advances in measurement devices for LOTs and XLOTs have improved their accuracy and reliability significantly. These advancements include:
Conventional formation integrity tests (FITs) for wells require closing the BOP and using the rig’s mud pumps, which can cause non-productive time (NPT). Alternatively, dynamic FITs can be performed using managed pressure drilling (MPD) without closing the BOP or incurring NPT. MPD methods use a closed-loop fluid system to accurately measure fluid flow in and out of the wellbore. These dynamic FITs can be conducted more frequently to verify that the wellbore can withstand the pressures associated with drilling fluids and well construction.
More software tools are available to aid in conducting FIT, including advanced data analysis programs that simulate well conditions to optimize test parameters and improve accuracy. Some software tools offer live monitoring and analysis for LOT and FIT for real time integrity assessment. More advanced software tools can be used for comprehensive well integrity and formation strength analysis.
Formation strength tests are critical processes in the oil and gas industry for ensuring well integrity and safety. Using advanced technology and adhering to the best practices will enhance the accuracy and reliability of these tests, contributing to safer and more efficient drilling operations. Contact us for information about IPT Global’s well integrity management solutions.
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