Sunday, January 13, 2019

Measuring Permeability Anisotropy

Knowing how fluids flow through a reservoir is fundamental to successful management of hydrocarbon reserves. Fluid flow is governed by the permeability distribution. The latest technique for measuring vertical and horizontal permeability uses a multiprobe wireline formation tester. Operated in open hole, this technique provides measurements before the completion is run allowing reservoir management to begin at the earliest stages of a field's development. 

Permeability - the ease with which fluids flow through rock- has long been identified as one of the most important parameters controlling reservoir performance. Yet it is one of the most difficult to measure. If permeability were the same at all places and in all directions- homogenous and isotropic - then measuring the flow through  a sample of rock would reveal its value. However, rock type and grain size may vary through a reservoir leading to variation in permeability. To complicate matters further, measuring permeability parallel to layers of sedimentary rocks may give a different value to a perpendicular measurement. Therefore permeability measured at the same point in the horizontal direction , Kh, may be different from permeability measured in the vertical direction, Kv. This directional dependency on any type of measurement is called anisotropy. A measurement, such as vertical permeability, in the same direction at two distinct points may also be different. Positional dependency is called heterogeneity. Needless to say, in the horizontal plane, horizontal permeability may have a maximum value, Kh, and a minimum value, Kh. Although anisotropy strictly refers to the directional dependency of a measurement, the ratio Kv/Kh is often used to quantify permeability anisotropy.

The anisotropic nature of permeability can affect any process in which a density difference exists between fluids, for example primary production below the bubblepoint, gas cycling, gas or water coning, waterfloods  and many steam process. It can also influence injection and production rates if the anisotropy is severe. Completion and treatment strategies must also take anisotropy into account - for instance placing perforations near oil-water or oil-gas contacts.

The experience of British Gas Exploration & Production Ltd. emphasizes the importance of anisotropy. The company discovered six small satellite fields of the Morecambe gas fields in the Irish Sea. 

The Triassic Sherwood sandstone reservoirs found there are common to all the Morecambe fields and typically 300 ft thick. Underlying this is an extensive aquifer. Most fields have high permeability- horizontally 200 md , but with individual layers up to 18 darcies. Faults close the reservoirs on one or two sides, with dipping beds sealing the remainder.

To predict the rate and direction of water influx into the reservoir, vertical permeability must be measured. The amount of water influx will determine reserves and, therefore, flow rate and revenue. Underestimating reserves will give a lower flow rate and influence project economics. Overestimating reserves will probably involve penalty payments on future gas sales contracts. 

A modeling study by British Gas showed that at high values of anisotropy- high vertical permeability - considerable reserves are trapped behind the rising aquifer. At the other extreme, low anisotropy - low vertical permeability- does not allow recovery of gas from unperforated layers. Optimum recovery occurs when anisotropy is large enough to retard water influx, but still small enough to drain the unperforated layers.

 Perforating policy for these fields will also be determined by anisotropy. If it is high, only the upper reservoir layers will be perforated to avoid water production. But high vertical permeability will allow drainage of unperforated layers. If anisotropy is low, more perforations will be needed to efficiently drain the field. Reperforating wells will probably be expensive as the likely development will use subsea platforms or those not normally manned. Hence the importance of measuring vertical permeability before perforating.

The problem is that anisotropy not only depends on direction, but also may vary with scale. For example, a single crystal may have an atomic structure that is anisotropic to properties such as electric current flow or acoustic propagation. But a piece of rock formed from randomly packed crystals may be isotropic to the same properties measured at a larger scale. At still larger scales, a series of isotropic rock layers, each with different values for these properties, will behave anisotropically. 

The scale dependency of permeability anisotropy is illustrated by measurements taken by British Gas on its South Morecambe gas fields. Permeability measurements of 1-in. [ 2.5-cm] core plugs yield anisotropies of 0.5 to 0.3. However, vertical pressure profiles over a 400-ft [122-m] thick layer in the producing gas reservoir are consistent with anisotropies as small as 0.002.

Such extreme values are caused by layering of rock on a scale smaller than the scale of the measurement - each layer has a different value of permeability, but all contribute to measurement. Two geological features in particular account for this type of anisotropy: crossbedding and shales. 

Crossbedding is the alternate layering of sands of different grain sizes or textures at an acute angle to the major depositional features. There is little difference between the mineral composition of alternating layers.

Shales have small grain size and usually low permeability. Dispersed shale, for example platy illite which blocks pore space, reduces the permeability of most formations, but does not contribute significantly to anisotropy. On the other hand, shale layers reduce or eliminate flow to adjacent formations and therefore contribute significantly to the anisotropy at some scale. 

Anisotropy is also dependent on shale continuity. For example, a continous shale may totally isolate one zone from another, in which case the permeability  anisotropy measured across the  shale will be zero. If, on the otheerr hand, the shale extends only a short distance from the well, the two zones will not be isolated. Fluid will follow a long, tortuous path around the shale, effectively decreasing the permeability measured across it. So the extent of the shale controls the permeability across it.  

Earlier we said that the  ratio Kv/Kh is often used to quantify permeability anisotropy. A more accurate definition would be to call this ratio vertical permeability anisotropy, which is a useful concept for vertical wells where vertical permeability plays such an important role in field development. For horizontal wells, however, the permeability anisotropy in the horizontal planes becomes equally important.  

Horizontal permeability anisotropy is caused by the depositional environment or by fracturees. Where natural fractures are oriented in one direction there will be a significant difference between the horizontal permeability measured , on a reservoir scale, in the direction of the fractures and that measured normal to them. When tectonic stresses are involved, permeability anisotropies may also occur, as microfractures, aligned with the direction of maxium horizontal stress, open up in the direction normal to the stress. It is also believed that stress anisotropy may cause minor permeability anisotropies without the presence of natural fractures by distorting the pore space. 

There are several different methods of obtaining permeability anisotropy, such as core analysis, well testing techniques and wireline formation tester measurements. One well testing technique- vertical interference testing - is successfully used by a wireline formation tester.

Picture above: Vertical interference test. The well is flowed through one set of perforations creating a pressure disturbance in the reservoir. If there is communication across an interval, a monitor pressure gauge at the second set of perforations will respond to the disturbance. The pressure response depends on the vertical permeability and the boundaries of the zone being tested.

In vertical interference testing, a well is flowed at one zone, creating a pressure disturbance through the reservoir. The effects are recorded on pressure gauges some distance away at a second zone in the same well. The pressure response at the second zone depends on several factors: communication between the two zones, vertical and horizontal permeabilities, and reservoir boundaries. Transient analysis of the pressure response reveals horizontal and vertical permeabilities.  

Vertical interference testing was first developed for well testing using two sets of perforations isolated by straddle packers. This method relies on perfect isolation between the intervals being tested- good packer seals and no casing or cement leaks- and is costly if several zones are to be tested. However, the modular design of the MDT Modular Formation Dynamics Tester tool, using various combinations of probes and packers, allow openhole vertical interference tests to be performed faster and at lower cost- although on a smaller scale.

British Gas used the MDT formation tester to perform five vertical interference tests. The tester configuration used a dual-packer module and a single-probe module. The dual-packer module employs two inflatable packers to isolate about 3.3 ft [1 m] of borehole and was used to create the pressure disturbance - the sink pulse. The single-probe module was mounted above to monitor pressure. The effective distance between the sink pulse and monitor probe was 6.5 ft [2 m] . Using a dual-packer module allowed high flow rates with limited pressure drop and also reduced sanding problems as the fluid velocity across the sand face is lower.

Prior modeling, using a range of vertical permeabilities, showed that the largest possible sink pulse would be required to generate a masurable pressure change across the 6.5-ft gap- the only limitation would be possible sand production. A 10,000-cm3 sample chamber was used to generate the sink pulse and high-precision quartz gauge was connected to the monitor probe. The plan was to flow the formation fluid into the sample chamber and monitor pressure at the monitor probe and between the packers. At the end of each test the pump-out module- also used to inflate the packers- could be used to empty the sample chamber.

The interpretation centers on the pressure transient measured at the vertical monitor probe. The amplitude of the pressure pulse originating at the dual-packer module determines the horizontal permeability, and the travel time gives the vertical permeability. 

Results showed that vertical permeability was between one and two orders of magnitude lower than horizontal permeability. Core measurements available at one depth agreed with the vertical interference tests. At another depth, the core data showed a much lower vertical permeability. 

The low permeability layer seen by the core data may not be areally extensive, whereas the pressure response seen by the MDT formation tester sees beyond this - a distance of three to five times the sink to monitor probe spacing is typical- into the more permeable reservoir. This may account for the discrepancy and shows the significant impact the results have on reserves and development options.

Three-probe Test in West Africa

Multiprobe vertical interference tests were conducted for AGIP recherches Congo, West Africa, to measure permeability anisotropy and to identify permeability barriers across reservoir sections.

The tool configuration for the multiprobe formation tester consists of three probes:
  • the sink probe - to induce a pressure pulse in the formation
  • the vertical monitor probe locate 2.3 ft [ 70 cm] above the sink probe and in the same vertical plane.
  • the horizontal monitor probe directly opposite the sink probe.

The monitor probes measure pressure transients induced at the sink probe. AGIP added sample chambers to this setup to recover clean, pressurized samples of formation water.

A typical sequence of events would be to position the tool and set all three probes against the formation. The integrity of each probe packer seal is checked by performing a small-volume drawdown test- a pretest. A good seal for a probe set in a permeable zone is indicated by a pressure response showing a drawdown followed by a buildup formation pressure. Similiar responses at all three probes are required before the interference test is allowed to proceed. The transient pressure data from pretest may be analyzed to obtain local permeability estimates as with previous formation testers. 

It is advantageous - but not necesssary - to have a constant flow rate during an interference test, and this is achieved by the flow control module.  Up to 1000 cm3 of fluid may be withdrawn from the formation at a specified flow rate during a test through either sink probe or the vertical monitor probe- both are connected to the flowline that runs through most MDT tool modules. The flow control module chamber is reset after test, emptying the contents into the borehole- using the pumpout module- or into a large sample chamber. 

Flowing pressure at the probe must be at least 30% of the mud pressure for the flow control module to operate. In some cases, as in depleted or low-permeability formations, the pressure may be too low to sustain a flow rate. An alternative method is to open the sink probe to a sample chamber attached to the tool and estimate the flow rate. One of the AGIP tests was repeated by opening the sink probe directly to a 1-gallon sample chamber, so that the two methods of providing a pressure pulse could be compared.

Interpretation begins as tests are recorded. Communication is indicated by pressure changes at the monitor probes in response to the pressure pulse. The degree of communication is indicated by the magnitude of the pressure drop. The pressure drop at the horizontal and vertical probes provide a quick estimate of anisotropy. 

Values of horizontal and vertical permeabilities come from transient analysis. Transient analysis involves identifying when spherical or radial flow regimes occur, choosing the location of zone boundaries from openhole logs in such a way as to be compatible with the indicated flow regimes, and, finally, estimating reservoir parameters during those flow regimes. 

One method of identifying the flow regimes present employs pressure derivative plots for which a prequisite is the flow rate history. The interpretation of flow regimes then proceeds in a similiar fashion to that during the interpretation of  a well test.

When the flow rate is unknown, an alternative method may be used. It relies on the fact that multiprobe testing measures pressure transients at two distinct locations away from sink. Fluctuations in flow rate will influence the two pressure transient measurements in some related way. The relationship is purely a function of the flow geometry and rock and fluid properties. This relationship- the G-function may be calculated by using both pressure transients. A plot of G-function versus delta time will approach a slope of -1.5 for spherical flow and -1.0 for radial flow. This approach was used to analyze the AGIP job.

Once the flow regimes are identified, specialized plots may be generated for the periods of spherical flow and radial flow. Spherical analysis allows first estimates to be made for horizontal and vertical mobilities and the porosity-compressibility product. Radial analysis give the horizontal mobility-thicknes product.

The initial estimates are used in formation response models coupled to a parameter estimator to arrive at the best estimate of formation parameters and achieve the best match between observed and calculated pressures. The final match is presented as verification plots- pressure versus time and lobe plots (pictures below). For a low plot, the change in pressure at the vertical monitor probe is plotted against the change in pressure at the horizontal monitor probe during both drawdown and buildup. 

 The separation between vertical monitor probe and sink probe - 2 ft [60cm] did not allow AGIP to test across all zones of reduced porosity that were indicated from petrophysical interpretation of the openhole wireline logs. Several vertical interference tests were conducted over the reservoir to evaluate vertical permeability statistically. Although some dry tests were encountered, no permeability barriers were found. 

 Results from the 1-gallon sample chamber test were in good agreement with the flow control test, and were also in good agreement with permeabilities measured by a drillstem test (DST) over this interval.

The anisotropy ratio for one reservoir from core plug data was 0.8 compared to 0.62 using the MDT tool measurements. The MDT tool results were considered to be more representative and have been incorporated by AGIP into their three-dimensional simulation model.

Two-Probe Test in Abu Dhabi

TOTAL used the MDT tool in four wells to measure permeability anisotropy in a Middle East carbonate reservoir prior to a proposed gas injection project. The test were carried out mostly between limestone and dolomite layers where permeability barriers were expected at the lithology change. 

The MDT tool configuration with single-probe modules was used to increase the spacing between the probes to 8 ft, so that each test would cover as much formation as possible. The flow rate source was the pumpout module, which can pump mud filtrate or formation fluids from the reservoir into the borehole.

The results from the drawdown permeabilities compare well to the stonely permeability log recorded by the DSI Dipole Shear Sonic Imager tool and show extreme permeability heterogeneity. However, results from the vertical interference test measurements show significant differences when compared to permeability measurements from cores. The vertical interference test analysis indicates much lower horizontal permeability at the depth at which core data are available.  High core horizontal permeability measurements are most likely caused by vugs and induced fractures and the fact t hat the measurements took place without overburden pressure.

Although core measurements showed vertical permeability to be almost as good as horizontal permeability, scaling up the data did not provide TOTAL with the correct value of anisotropy for their reservoir model- they had to use a much smaller value to match reservoir performance. The MDT tool test results showed reasons for this. Several MDT tests indicated the presence of permeability barriers; other MDT tests indicated that previously suspected barriers were not present. This enabled TOTAL to revise their simulation model for the gas injection program.

A Barrier Removed?

The importance of permeability anisotropy to sound reservoir management is not in dispute. Vertical interference testing with the MDT tool provides measurements of horizontal and vertical permeability early enough to attack problems of well completion design, stimulation planning and horizontal well trajectory. The resolution of the measurement fills the gap between that of well tests and that of core data so that reservoir models may be refined, leading to better field development strategies, such as enhanced oil recovery programs and infill well placement. 



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