New Test Probe Yields Key Reservoir Answers
Kate Arman and Robin Martin, Premier Oil; Chris Tevis and Ilaria De Santo, SPE, Schlumberger
Extreme downhole conditions pose a challenge to formation testing. Acquisition of accurate reservoir pressure data and high-quality formation fluid samples has proved difficult in cases of low reservoir permeability, extremely viscous crude oil, or unconsolidated formations with poor borehole conditions. Operators have often considered these wells untestable. When testing is possible, it is frequently time consuming and costly with the need to set and cement pipe, shoot perforations, and bring in coiled tubing to run the test. Even then, formation pressure estimates on such wells are frequently inaccurate.
However, a new tool has proved able to extend formation testing parameters to extreme formation and borehole conditions. The Saturn 3D radial probe (Fig. 1) developed by Schlumberger is a complementary module to the Modular Formation Dynamics Tester tool. The probe is capable of performing accurate pressure tests in fluid mobilities as low as 0.01 md/cp, and obtaining high-quality fluid samples in mobilities lower than 1 md/cp.
In Mexico, a friable sandstone reservoir containing 7.5 °API crude oil in extremely unconsolidated formations was successfully sampled by the 3D radial tool in a very rugose borehole with 12% ovality. The data collected would have been unobtainable with previous test assemblies and was critical for a subsequent thermal recovery design. Despite the difficult conditions, the new tool was able to conform to borehole irregularities to achieve and maintain a reliable hydraulic seal.
Formation Fluid Challenges
Acquiring representative samples of heavy, viscous crude is only part of the story. A North Sea operator took full advantage of downhole fluid analysis (DFA) to characterize viscous, biodegraded oil in a poorly consolidated field. The Catcher area fields, operated by Premier Oil on behalf of colicensees Cairn Energy and Wintershall, contain 300 million bbl of original oil in place, making them one of the most significant recent discoveries in the United Kingdom Continental Shelf. Six wells and three sidetrack boreholes have been drilled to date.
The fields are partly characterized by a series of sand injectites, overpressurized sediments that are remobilized and forced upward to intrude into overlying layers. Injected sands are typically characterized by high porosity and high permeability, which is why they are often considered as attractive hydrocarbon targets. However, injectites often range from poorly cemented to unconsolidated, which makes attempts to sample high-quality fluid very challenging.
The fluids that characterize the Catcher fields underwent trap-spilling migration and methanogenic biodegradation, which have resulted in vertical and horizontal fluid variations between the fields. The resulting factor affects oil composition and viscosity. With the complex geometries of the injectite system, the ability to understand the variation of fluid properties can lead to an improved knowledge of the 3D connectivity of the reservoirs.
To be able to maximize recovery, the Catcher license group needed to analyze the crude oil in situ. The group chose to use wireline formation testing with the 3D radial probe and the Schlumberger InSitu Fluid Analyzer (IFA) system for DFA. The analyzer is able to assess the presence of flow assurance impediments, such as asphaltene, scale, hydrates, and paraffin. Many of these appear when formation or flowline pressure declines past a threshold that is determined by their composition. The ability to perform compositional analyses of formation fluid in situ results in a clear assessment of one of the Catcher group’s major concerns—reservoir connectivity.
However, the use of traditional wireline test analysis equipment is limited by factors such as formation fluid viscosity and mobility, and the ability to obtain and maintain a hydraulic seal. In addition, the time needed to obtain a representative sample of uncontaminated formation fluid can add significantly to operating costs.
Improved Technology Pairing
The Catcher group used traditional formation testing equipment and predecessors of the IFA system to acquire and analyze well samples obtained before this year. The data collected in the wells was analyzed using the Flory-Huggins-Zuo (FHZ) equation of state (EoS) program to better understand the vertical and horizontal fluid variations and confirm the previous understanding of the fluid continuities and discontinuities between fields.
Beginning this year, the group has used the 3D radial probe module in combination with the latest IFA tools to maximize the quality of data obtained from wells tested in the Catcher area’s Bonneville field.
The 3D radial probe module is fully compatible with the Modular Formation Dynamics Tester tool and significantly extends the tool’s operating limits in testing low-permeability areas, unconsolidated formations with rugose boreholes, and highly viscous crudes. The 3D radial probe features four orthogonally positioned large area probes spaced around an inflatable packer element that conforms to irregular borehole profiles. Each of the four elliptical probes has almost 20 in.2 of surface flow area. Together, they provide a surface flow area of 79.44 in.2
Besides improving the range of fluid sampling in tight formations or in heavy oil areas, the 3D radial probe facilitates the determination of fluid gradients and anisotropy and the measurement of far-field permeability (Fig. 2). Data collected by the tool benefits subsequent well test design. Interval pressure transient testing with reduced storage effect for flow regime identification is also possible.
Solving the Fluid Puzzle
The variations in biodegradation and asphaltene content in the Catcher area fields result in varied fluid distribution and viscosity across the different fields. Asphaltene variations determined by the IFA can be analyzed using the FHZ EoS program to enable the prediction of equilibrium gradients. Specifically, measurements in six wells and one sidetrack borehole yielded 250 pressure levels and several different oil and water gradients. Multiple models are required to describe and predict fluid variations, with depth confirming the predicted continuities and discontinuities within and between fields.
Several factors became apparent from initial analyses. Biodegradation of the oil seems to occur in accordance with migration of the oil across the sand systems. There are variations in viscosity and asphaltene content. These variations were identified initially by the DFA and most recently by the IFA, and were seen as compatible with the migration paths modeled by the Catcher group.
The DFA/IFA analyses were used on the Bonneville wells to provide a real-time indication of reservoir connectivity. Beforehand, a prediction of fluid coloration was made. When real coloration was compared with predicted coloration, matching samples were deemed to come from dynamically connected reservoirs. While pressure measurements can indicate hydraulic connectivity, combining them with the fluid coloration gives a much more reliable indication of the dynamic connectivity.
The major benefit of using the 3D radial probe was its speed in obtaining uncontaminated samples for real-time analysis by the DFA/IFA. Although traditional testers used previously were equipped with a focused sampling probe in which focused extraction of pure reservoir fluid can be separated from contaminants in the flow stream, the high viscosity of the fluid in the formation, combined with the unconsolidated sands, caused unacceptable time delays in the cleanup process.
Typically test times ranged from 5 to 11 hours per test. The use of the 3D radial probe reduced the cleanup time by 65% to 75% and required a maximum drawdown of 35 psi, compared with a drawdown of more than 500 psi needed for the probe-equipped tool.
The Catcher area fluid testing and analysis project marked the first application of EoS analysis in a multiwell study of fields characterized by variable biodegradation. Sample coloration measured in real time by the DFA/IFA module was used to assess vertical and lateral reservoir connectivity by quantifying the fluid’s asphaltene content.
The use of the 3D radial probe greatly reduced the Catcher group’s test time and the rig time needed for sampling, as well as enabled a higher quality of uncontaminated samples to be obtained for analysis.
The authors wish to thank the Catcher group for permission to use its data in this article.
New Methods Developed to Manage Subsea Vibration-Induced Fatigue
Rob Swindell, Xodus Group
The vibration assessment of subsea systems has largely been limited to vortex-induced vibration of riser systems and unsupported pipeline spans (i.e., environmental loading) caused by flow past the outside of a riser or conductor. But now, piping vibration caused by process excitation is becoming an issue on manifolds and jumpers, in part associated with increasing production rates. Though the likelihood of a failure is low, the consequences can be high, resulting in an unacceptable level of risk. As well as piping integrity issues, additional vibration-related problems have also been experienced with valves and instrumentation.
Process Excitation Mechanisms
There are a number of different sources of excitation and these generally depend on the type of process fluid within the system. The following three mechanisms are the most common.
This is caused by broad band, low-frequency energy, generated by “single phase” turbulent flow through valves, expansions and bends—essentially anything that disturbs the flow. This can lead to excitation of the low-frequency modes of the piping system by energy transfer from fluid momentum to the pipe, resulting in low-frequency vibration (up to possibly 50 Hz). This is widespread in most processes and depends heavily on the velocity and density of the fluid.
This encompasses slug, bubble, annular, and churn flow. The frequency range of the resulting excitation is heavily dependent on void fraction and flow regime.
This is linked to gas flow through a flexible riser or jumper, sometimes known as the “singing riser.” This is where gas across the internal corrugated geometry within the flexible piping causes vortex generation. This can cause a pressure fluctuation, or pulsation, with a frequency and amplitude that are dependent on the gas velocity. This pulsation can drive the flexible piping at either end at very high frequencies—in some situations as high as 1,000 Hz—causing fatigue damage to accrue very quickly. The phenomenon is typically only experienced on dry gas systems, so it can be an issue on gas export, gas injection, and gas lift systems.
The Hidden Threat
Pipe design and construction can present a number of unique challenges in subsea developments, given their re-moteness and complexity to access. A vibration issue may occur subsea without any obvious sign topsides.
One of the key challenges is the practical difficulty of obtaining subsea measurements on equipment installed on the seabed. This can be very expensive, usually requiring a dive support vessel to be on station to deploy and recover the monitoring instruments. For fatigue assessment, direct strain measurement usually would be preferred, but it is often impossible to perform on subsea equipment that has already been deployed, such as production manifolds, pipeline end manifolds, and flowline termination assemblies. In practice, we often must measure the vibration acceleration at nonideal locations and infer the system fatigue damage by linking the measurement data with a suitable simulation.
Another challenge relates to the often limited real-time capability of the measurement instruments. Fatigue damage can accrue relatively quickly. The delay between taking the measurement and recovering and analyzing the vibration data—which may be days or weeks—often results in an unacceptable risk.
New Industry Guidance
To counter some of these problems, Xodus Group has acted as a technical author of a soon-to-be-published Energy Institute (EI) document that builds on the topsides version of EI’s guidelines for piping vibration—providing a risk-based methodology and good design practice—and tailors an approach specifically designed for subsea equipment. The anticipated document included input from a wide variety of operators, equipment designers,
This latest EI guidance, which is slated to be released this summer, is based solely on subsea equipment. The document includes a step-by-step approach to identify and solve potential issues early in the design cycle to achieve a fatigue-resistant design. There are a number of key elements.
Defining Good Design Practice
This includes guidance on the design and layout of process piping, how branch connections should be made, and advice on rough-bore flexibles.
Initial Risk Assessment
This includes screening methods using information from piping and instrumentation diagrams, process flow diagrams, and in some cases, piping isometrics. The existence of potential hot spots stemming from any of the common excitation mechanisms is identified on the build being assessed, considering the static and dynamic response of the piping. The method uses a series of algorithms and process and piping information to ascertain a likelihood of failure (LOF) score for each excitation mechanism. Responsive actions are determined based on the LOF score. The method can be used to check the sensitivity to changes in the process conditions and/or gross structural parameters (e.g., pipe diameter, wall thickness, and degree
If the fatigue risk is not acceptable, guidance is provided on how to perform a detailed fatigue simulation for a variety of excitation mechanisms. Once the level of excitation is predicted, using empirical, analytical, or computational fluid dynamics (CFD) techniques, a finite element model is created to assess the response of the piping to the vibration acceleration and dynamic stress. This requires knowledge of the piping system layout, supports, process conditions, and structural boundary conditions (Fig. 3).
The results provide an assessment of the fatigue life under certain operating conditions and the effect of varying those conditions. In addition, the results help to identify the best locations to place vibration sensors for subsequent monitoring activity. However, the industry still needs better validation data to ensure accurate simulation methods, particularly for excitation generated by multiphase flow.
Monitoring System Specification
There are some key considerations when specifying the monitoring system. They include the frequency and dynamic range, as well as the phase relationship between sensor pods and how transducers will be installed and mounted to parts of the structure. Most important is how the data will be recovered and used.
Guidance is provided on the verification steps required at the construction stage to ensure that what is built correlates with the intended design. This is particularly important for piping supports, which have an important bearing on the vibrational response of the system. Verification may also include nonintrusive modal testing of the piping systems and associated support structures. This will help to provide validation data for any previous simulations. If used with temporarily installed strain gauges, this type of testing in the construction yard can also provide useful information about the relationship between the vibration acceleration levels at locations where measurements will be made on subsea infrastructure, and the dynamic stresses at potential fatigue hot spots that could not be monitored subsea because of access restraints.
Monitoring During Operation
This includes checking of the raw data (signal statistics, including kurtosis), data interpretation, and the interface with simulation to provide an assessment of the fatigue performance of the equipment under different operating conditions. An example of a fatigue assessment based on the data logged from subsea vibration sensors is shown in Fig. 4.
As flow rates increase, the industry must better understand the types of dynamic forces that are generated by multiphase flow in piping systems. A new joint industry project (JIP) managed by Xodus addresses this area of uncertainty, with support from key industry operators and equipment vendors.
This initiative will derive, from a series of “industrial scale” tests, the power spectral density (PSD) of the forces acting on piping under a variety of void fractions and superficial velocities, designed to include the most common flow regimes. This would act as validation data for CFD predictions and could provide an empirical means of determining the force PSD acting on a pipe bend, given basic flow parameters. It is also intended that this new JIP will provide a series of benchmarks for the use of CFD to predict two-phase flow forcing functions.
Following the Macondo incident in 2010, the integrity of subsea systems is receiving increased attention. Research into vibration-induced fatigue and its management in the subsea environment is attracting greater emphasis and commitment in the industry.
As flow rates increase and exploration and production go into deeper, harsher environments, subsea equipment is becoming more complex to enable improved production performance. New developments in subsea processing and separation are also on the horizon. Finding the balance between design, simulation, and monitoring is crucial to maintaining the integrity of equipment and to pushing ahead to recover more reserves.
This article is taken from a paper presented at the 2013 Australasian Oil & Gas Subsea Exhibition and Conference, 20–22 February in Perth, Australia.