Measuring and testing – Borehole or drilling – Fluid flow measuring or fluid analysis
Reexamination Certificate
1999-12-20
2002-02-05
Williams, Hezron (Department: 2856)
Measuring and testing
Borehole or drilling
Fluid flow measuring or fluid analysis
C073S152310, C073S152240, C073S152280, C073S152550, C073S061410, C166S254200, C175S005000, C702S012000, C250S255000
Reexamination Certificate
active
06343507
ABSTRACT:
FIELD OF THE INVENTION
This invention relates to a method for improving the quality of a formation fluid sample. In particular, the invention relates to a real-time method for determining the composition of a formation fluid and/or differentiating between oil-base filtrates and formation fluid hydrocarbons during the process of pumping fluids from a downhole formation for the purpose of taking a formation fluid sample.
BACKGROUND OF THE INVENTION
It is desirable to evaluate formation fluids that may indicate the existence and/or type of subsurface hydrocarbon fluid reservoirs. To assist in this evaluation, wireline formation tester tools are commonly used during openhole logging operations to recover formation fluid samples and to determine the type and distribution of formation fluids. Methods of positive fluid type identification usually come from inspection and/or analysis of recovered samples at the surface. As a result of these methods there are long-standing difficulties associated with wireline fluid sampling operations such as: mud filtrate invasion into the formation fluid, establishing and maintaining a seal between the tool probe and the borehole wall, and drawing down the pressure of the formation fluid below saturation pressure. These and other issues are addressed by downhole tools such as the tool described in U.S. Pat. Nos. 4,860,581 and 4,936,139 issued to Zimmerman et al.
The Zimmerman patents disclose a downhole tool that can take formation fluid samples and determine formation properties from these samples. These downhole wireline tools may be modularly constructed so that a tool can perform multiple tasks in a single descent of the tool into the borehole.
FIG. 1
shows such a downhole tool. This tool
1
has a probe module
2
that establishes fluid communication between the tool and the earth formation
3
via a probe
4
. This tool contains a pump out module
5
for pumping fluid from the formation into the tool and a module
6
to analyze fluid from the earth formation.
FIG. 1
illustrates the problems associated with taking a formation fluid sample. The formation
3
contains a mixture of both the desired hydrocarbon type fluid
7
and the undesired contaminated fluid filtrates
8
. The less contaminated hydrocarbon fluid is often referred to as the ‘clean fluid’. The borehole annulus
9
also contains contaminated filtrates. Contaminated formation fluid
8
is in closer proximity to the borehole and a greater portion of that fluid is initially in the mixture. During the pump out process, the composition of this mixture will continually change until the composition begins to stabilize. From the fluid analyzer
6
, it is determined when the composition of the fluid begins to stabilize. Once fluid stabilization has occurred, and depending on the portion of hydrocarbon in the mixture, the incoming fluid may be diverted into the sample chamber
10
. However, during any attempt to retrieve the clean fluid, it will be necessary to pump out the contaminated formation fluids before getting to the desired clean formation fluid.
In addition to the mixture of contaminated and clean fluids, other factors can affect the fluid sample quality. These factors include the rock properties, the mud filtrate invasion volume, the pressure differential used to produce the fluid, and the clean up time. The rock properties usually cannot be modified, but selection of the sample interval can alter the influence of the vertical permeability in some cases. The fluid flow geometry into a probe
4
, even under stable conditions, can include a significant vertical component from the borehole-invaded zone that contains mud filtrate contamination. Sample points taken near vertical flow barriers can reduce the influx of mud filtrate into the probe.
Drilling operations to create the borehole require various types of drilling muds. The use of oil-based drilling mud systems causes major problems in wireline logging including problems during attempts to obtain high quality fluid samples. These mud filtrate fluids are mixed in the formation oil. Therefore, quantification of the oil-base material in the formation oil becomes difficult without laboratory analysis. The presence of even small volumes of oil-base filtrate in the sample can significantly alter the pressure-volume-temperature (PVT) properties of formation oil. Generally, the additives in the filtrate change the character of the optical density response curves of the oil-based mud filtrate. This change affects the optical analysis of the filtrate and increases the difficulty of distinguishing an oil-based filtrate from a formation hydrocarbon fluid. Because of this difficulty in making this distinction, the quality of a fluid sample may be unreliable.
One conventional sample taking method that addresses this problem is to pump fluid from the formation through the tool for a predetermined period of time or a predetermined pumped volume of fluid. It is assumed that after this period, the fluid passing though the tool should be at an acceptable contamination level. Although using empirical models or reservoir simulators to estimate the time required to obtain an acceptable fluid sample is appealing in concept, it requires significant knowledge of the formation rock properties, formation fluids, mud filtrate, mud cake, formation damage zone, flow patterns, and other information in the near wellbore zone which is not available.
A second approach is explained using the tool in
FIG. 1. A
downhole tool
1
is suspended in a borehole
9
from a wireline
11
or drill pipe. In this method, a probe
4
in fluid communication with the tool body is also in contact with the borehole wall
12
. To retrieve the formation fluid, a pressure drop is created in the tool across the probe. This pressure drop causes formation fluid to flow from the high-pressure formation to the lower pressure probe and into the tool. The pumpout module
5
is used to draw fluids from the formation, through the tool flowline
13
and out into the borehole (if desired). As fluids pass through the tool, the probe module measures their resistivity and temperature and the optical fluid analyzer (OFA)
6
measures their optical properties (i.e. fluid density).
Optical data are processed in real-time to quantitatively determine flowing oil and water fractions, and to obtain a qualitative indication of the amount of free gas in the flow system. Optical fluid responses vary for different materials. As shown in
FIG. 2
, there are significant differences between water and oils. The responses of water
14
and oils
15
and
16
show these differences When the fluid analysis begins to show stabilization, a fluid sample is taken by diverting fluid into a sample chamber.
A flowline
13
passes though two independent optical sensors in the OFA module
6
. In one sensor, absorption spectroscopy is used to detect and analyze liquid. In the other sensor, a special type of optical reflection measurement detects gas. These detections allow wellsite personnel to decide whether to divert the fluid flow into a sample chamber for retrieval, to continue to expel the fluid into the borehole or to a dump chamber, or to increase the sampling pressure above bubblepoint. This module can also verify that the formation contains only water or only gas and/or that a sample is not necessary. Thus, the sample chambers in the tool are kept available only for desired fluids. After a decision has been made to switch from pumpout mode to sampling mode, the OFA module continues to monitor the fluid in the flowline, particularly to verify that production remains above bubblepoint.
As stated, the OFA module has a visible and near-infrared absorption spectrometer for oil/water discrimination and a refractometer for free gas identification. Each OFA sensor responds to one of two basic optical properties, namely absorption and index refraction. These properties are measured by passing light through a window opening onto the flowline. The measured absorption spectra depend on the composition of the sampled flui
Butsch Robert J.
Felling Michelle M.
Morris Charles W.
Christian Steven L.
Ryberg John J.
Salazar JL (Jennie)
Schlumberger Technology Corporation
Wiggins David J.
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