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Tuesday, 16 September 2008

Real-time Completion Monitoring of Deepwater Wells

Andrey Bakulin and Mikko Jaaskelainen, Shell, and Alexander Sidorov and Boris Kashtan, St. Petersburg State University

Real-Time Completion Monitoring (RTCM) is a new non-intrusive surveillance method for identifying permeability impairment in sand-screened completions that utilizes acoustic signals sent via the fluid column. These signals are carried by tube waves that move borehole fluid back and forth radially across the completion layers. Such tube waves are capable of "instant" testing of the presence or absence of fluid communication across the completion and are sensitive to changes occurring in sand screens, gravel sand, perforations, and possibly the reservoir. That part of the completion with differing impairment from its neighbors will carry tube waves with modified signatures (velocity, attenuation). The RTCM method would require permanent acoustic sensors and, thus, could be thought of as "miniaturized" 4D seismic and "permanent log" in an individual wellbore.


Completions lie at the heart of deepwater production and constitute a large portion of the overall well cost. Great multidisciplinary effort is put in up front to design wells right. This contrasts greatly with the production stage, where little information is available to detect problems, optimise the inflow and prevent expensive workovers. Sand screen plugging, incomplete packing, development of "hot spots" in screens, destabilization of the annular pack, fines migration, near-wellbore damage, crossflow, differential depletion, compartmentalization, and compaction represent a typical list of challenges that are extremely difficult to decipher based on several permanent pressure and temperature gauges alone.

The aim of our study was to develop RTCM as a new method that can characterise permeability impairment of the sand screen, gravel, perforations, and the immediate near-wellbore space.


Physical principles that allow for the estimation of permeability from acoustics waves are well-known for open boreholes where permeability from Stoneley wave became the only direct technique of estimating in-situ permeability from wireline logs. Tube or Stoneley wave is a fundamental axisymmetric mode that represents a piston-like motion of the fluid column resisted by the borehole wall. When tube waves encounter a permeable region, their signatures change since the radial motion of the fluid is no longer fully resisted by the borehole wall and part of the fluid can escape in and out of the formation (Figure 1a). This implies that tube-wave velocity decreases and attenuation increases with increasing fluid mobility (ratio of permeability to viscosity). RTCM extends ideas of open-hole Stoneley-wave logging to wells with sand-screened completions typical for deepwater. These wells have additional layers between the formation and borehole fluid, such as sand screen, gravel sand, and casing (Figure 1b). The sand screen and gravel pack prevent migration of reservoir sand into the wellbore and maintain the integrity of the reservoir around the wellbore. The completed well has one essential similarity to the open-hole model, i.e., in a normal flowing well there has to be fluid communication across all layers of the completion. Our objective was to analyse the effect of broken fluid communication across the sand screen (or perforations) through the signatures of tube waves.

Figure 1: (a) The tube wave attenuates and slows down when it encounters the permeable interval that can exchange fluids between borehole and formation. (b) Schematic cross-section of a sand-screened completion in deepwater well. Sand screens: c) slotted PVC screen used in this experiment; d) a premium screen, named as Excluder (from Baker), e) wire-wrapped PVC screen.

RTCM concept

Figure 2 depicts two possible configurations of the RTCM method: "repeated or permanent log" (transmission) and "mini-4D seismic in a well" (reflection). In both cases, we detected changes in acoustic signatures of tube waves over time and inferred changes of permeability along the completion. In transmission configuration, we measure velocity and attenuation of the tube waves(s) along the completion and thus need sensors along the sandface (Figure 2a). In reflection configuration, we need sensors only above the completion and analyse the change in reflected arrivals from permeability interfaces (Figure 2b).

Figure 2: Conceptual design of RTCM configurations:

a) "Repeated or permanent log" (transmission configuration); b) "Mini-4D seismic in a well" (reflection configuration).

It can be shown that such measurements can be performed while the well is flowing, thus providing valuable information in real time to well engineers and production technologists. Such information allows them to detect changes in permeability in and around the well (and thus the inflow ability) in real time,
identify the well structure responsible for any problems (screen, perforation, etc.),
help design best practices for drawing the wells without impairing them,
raise red flags early on when problems are not acute and can be fixed with lighter effort, and help characterize cross-flow and differential depletion in wells with multiple commingled producing intervals.

We conducted a full-scale laboratory test of the RTCM concept when permeability impairment is caused by sand-screen plugging in a completion without agravel pack.

Full-scale laboratory test

The schematics and an actual photo of the horizontal flowloop setup we used for experimental measurements are shown in Figure 3. The outer pipe (casing) is modeled with glass pipe. The inner pipe (PVC sand screen) is positioned inside using plastic centralisers.

Figure 3: (a) Sketch of the flowloop setup with the model of sand-screened completion in horizontal well. (b) Photograph of the actual setup with a glass outer pipe (no perforations).

To model an open sand screen ("open pores"), we used a PVC pipe with 0.0002 m slots (Figure 1c). The plugged sand screen was modeled with a blank PVC pipe without slots and is referred to as "closed pores". The annulus between the inner and the outer pipe is filled with water. Measurements are conducted with a 24-level hydrophone array (35 cm spacing) and a piezoelectric source, both lying down at the bottom of the inner pipe.

Idealized completion model

Actual sand screens can be quite complicated (Figure 1d), but we assume that the screen can be represented by a homogeneous effective pipe, both in terms of mechanical and hydraulic properties. If this pipe is not permeable (plugged screen), then the laboratory setup can be simplified to this idealized four-layered model: fluid-elastic inner pipe (screen) Р fluid-elastic outer pipe (casing). This model of two concentric elastic pipes with a free outer boundary supports four axisymmetric wave modes at low frequencies:

    li>TI tube wave supported by the inner pipe
  • TO - tube wave supported by the outer pipe

  • PI - plate (extensional) wave related to the inner pipe

  • PO plate (extensional) wave related to the outer pipe.

Figure 4: Pressure seismograms with successive amplifications for a four-layered model with closed pores (no gravel pack) using model with glass outer pipe and plastic inner pipes. (a) The largest arrival is a fast tube wave (TO - 1030 m/s) related to the outer glass pipe. (b) The smaller arrival is a slow tube wave (TI - 270 m/s) related to the plastic inner pipe. (c) Plate waves are of even smaller amplitude (brown PO - 5410 m/s, green PI - 1630 m/s).

Figures 4 shows synthetic seismograms for a four-layered model similar to the experimental setup. The dominant arrival is a fast-tube wave associated with the outer pipe (TO), whereas the slow-tube wave supported by the inner pipe (TI) is weaker. If the inner pipe becomes permeable (open to flow sand screen), then both tube waves experience attenuation and slow-down.

"Permanent or repeated log" (transmission)

Let us look first at transmission signatures Р velocity and attenuation Р in the presence of open and plugged screens. Figure 5a shows the raw data recorded in the case of no screen and a screen with "open" or "closed" pores. Despite pipe joint reflections, there are clear differences between three scenarios. First, in the absence of a screen, there is only one (fast) tube wave present with a velocity of about 1050 m/s.

It experienced some amplitude loss, possibly due to intrinsic attenuation in the recording cable. When an impermeable inner pipe was added (closed pores), a slow tube wave appeared, and the fast tube wave became more attenuative. When the inner pipe became slotted (open pores), then fluid on both sides of the PVC screen started to communicate, and this led to a very strong attenuation of both tube waves. Thus, a greatly increased attenuation of both fast and slow tube waves was the first-order diagnostic for open screens, whereas reduced attenuation was characteristic for plugged screens.

Additional diagnostics can be established by analyzing energy distribution as a function of frequency between these two cases. Figure 5b shows slowness-frequency displays. Both fast and slow tube waves with approximately the same velocities of 1100 m/s and 350 m/s are clearly seen in the plugged and open cases, however, the slow wave is completely absent without a screen. In a plugged screen, the fast wave carries maximum energy in the frequency range of 300-600 Hz close to the dominant frequency of the source, whereas lower and higher frequencies carry less energy. In contrast, the spectrum of the fast wave in an open screen has a big energy "hole" between 300 and 600 Hz where the fast wave is attenuated so strongly that even higher frequencies (600-900 Hz) carry more energy. This behavior suggests that fast-wave energy is severely attenuated in the medium frequency range, whereas it is still preserved in the high-frequency range.

Figure 5: Seismograms (a) and slowness-frequency displays (b) of experimental data. "No screen" shows traces in the absence of an inner pipe. "Open pores" is for a slotted sand screen, whereas "closed pores" is for a blank pipe (no slots). Note that the fast tube wave is least attenuated in the absence of a screen, attenuated in closed pores and substantially absorbed in open pores.

Let us now compare this behavior with the poroelastic reflectivity modeling. Figure 6 shows synthetic seismograms computed for a glass setup. The sand screen is modeled as a poroelastic Biot cylinder. Similar to the experiment with closed pores, we observed two tube waves with the fast tube wave dominating in amplitude. In the presence of a screen with open slots, both waves experienced strong changes. The fast tube wave experienced moderate attenuation and change of waveform.

Figure 6: Synthetic data computed for open and closed pores in the glass setup. (a) Overlay of pressure seismograms for open (red) and closed (black) pores showing that the fast tube wave in a permeable screen experiences attenuation and dispersion. Blue and red lines denote moveout velocities of the fast (1030 m/s) and the slow (280 m/s) tube waves. (b) Slowness-frequency spectrums.

The slow tube wave transformed into a complex packet with weak amplitude. The following physical interpretation can be given to the modeled results. A tube wave is born when the piston-like motion of the fluid inside the pipe creates a radial expansion that is resisted by the elastic pipe. The slow wave is supported mainly by the inner pipe. When this pipe becomes slotted, radial movement of the fluid is no longer resisted since liquid can freely escape to the annulus, thus leading to a strong attenuation of this wave. In contrast, the fast wave is supported mainly by the outer glass solid pipe. In addition, when the inner pipe becomes permeable, a piston-like motion of the fluid in the fast wave can exchange the fluid between the outer and the inner fluid columns, thus creating a moderate attenuation.

The slowness-frequency spectra for open pores (Figure 6b) shows that, similar to the experimental results, the fast wave experiences anomalously high attenuation in the medium frequency range of 350-700 Hz. A more robust display averaging over small, medium and high frequencies is shown on Figure 7. A comparison of Figure 7a and 7b confirms the qualitative agreement between experiment and modeling. In both cases, the fast wave exhibits anomalous amplitude decrease in the medium frequency range, while still preserving higher and lower frequencies. This amplitude decrease should be attributed to anomalous attenuation caused by fluid movement through the slotted porous screen. The frequency range with resonance attenuation is controlled by permeability, i.e., the lower the permeability, the higher the frequency of the band with anomalous attenuation of the fast wave. Therefore, central frequency of the band with anomalous attenuation of the fast tube wave is an additional useful diagnostic of the screen permeability.

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posted by The Rogtec Team @ 16:31  0 Comments

Wednesday, 10 September 2008

4th Generation Seismic Oil & Gas Industry History Events

David Bamford

Nearly seventy years ago, one of the more notable events in the history of the global oil & gas industry occurred when the first offshore seismic was shot in the shallow waters of the Gulf of Mexico. Of course, seismic (typically refraction or 'radial' shooting around salt domes) had been acquired onshore in the USA for the previous twenty years but Shell Oil took the adventurous step of going offshore. I was told this story nearly twenty years ago by a gentleman called Sid Kaufman who was Shell Oil's chief geophysicist at the time. As I recall, the decision was made to emulate the onshore approach, with a shooting party and a recording party, and so two shrimp boats were hired in Galveston for the princely sum of $50 or so. After a successful first project, expenses were submitted and came back with the comment from the 'boss' (an accountant for sure!) "too expensive, next time use one boat! And so towed streamer seismic had to be, and was, invented, allowing just a single boat to be used"!

Well, it's a story and my memory is not what it used to be but it set me thinking about the phases of progress in the seismic technology business and whether we could describe these phases as the drillers do their offshore rigs I guess they are up to '5th Generation' by now. My thinking goes somewhat like this:

1st Generation Seismic = 2D

2nd Generation Seismic = 3D

3rd Generation Seismic = 4D.

Now I know I have skipped across several technology 'leaps' here for example, from onshore to offshore, from explosives to vibroseis and airguns, and of course from analogue to digital recording but I'm trying to define phases that when they were introduced produced a quantum shift in the exploration and exploitation of oil and gas and for which oil & gas companies were prepared to pay a premium for access to the new approach. Of course, in time and in turn, each of these approaches become a commodity, with many competing offers, and bid mainly on price.

So what might be described as 4th Generation Seismic? Perhaps we could start by asking what it is that oil & gas companies seem willing to pay a premium for nowadays (as opposed to accepting the currently high prices for, say, conventional 3D driven by an out-of-kilter supply/demand balance). I would like to focus on just four examples Continuous Seismic Surveillance; Wide-Angle; Multi-Azimuth; Multi-Component (2C and 4C).

What do each of these offer?
Continuous Seismic Surveillance extends 4D methodology. Offshore, permanent sensors (with up to 4 components: X, Y, Z and pressure) are installed, usually in a cable, in the sea-bed above any oil or gas field in a one-time installation before production starts. Then a relatively inexpensive seismic source vessel can sail above these sensors whenever required and generate a "repeat 3D". In theory, this could happen as often as once a week at a repeat cost of as little as $100k, giving real-time data for analysis of reservoir dynamics throughout a field's life. Onshore, a similar approach can be envisaged although permanently installed down-hole sensors are perhaps more likely. Such surveillance should be thought of as a component of the Digital Oil Field which I discussed at some length in a ROGTEC Issue 11and so will not pursue further here.

Wide-Angle and Multi-Azimuth Seismic were originally conceived of as two different ways of addressing a similar problem, namely how to image beneath lithologies such as salt or basalt that limit the ability of conventional 2D or 3D seismic to 'see through them' to image structures below. An example might be where a structural feature such as a rift system lies below a layer of salt, for example in the Santos basin, offshore Brasil or the Gulf of Suez, offshore Egypt, or beneath basalt, for example in the Rockall basin, offshore Ireland here Wide Angle Seismic seems to deliver. Elsewhere, more rugose surfaces (such as the Messinian unconformity in the Eastern Mediterranean) or salt bodies (Gulf of Mexico; Angola) might prevent illumination of deeper geology when data is acquired along a particular azimuth here Multi-Azimuth Seismic seems to deliver.

However, as the apparent leader in this area CGGVeritas makes clear, these two approaches have somewhat merged and have benefits beyond what was originally conceived. There seem to be two reasons for this. First of all, survey design is key so as to provide the optimum combination of target illumination, sampling, data quality and cost of acquisition. Second, the processing of Wide- and Multi-Azimuth has challenged conventional processing techniques, leading to the adoption of true 3D algorithms and workflows. The combination of this true 3D approach to processing, combined with improved illumination and data quality during acquisition, leads to great improvements in image quality in all sorts of geological settings, especially complex ones.

Multi-Component Seismic is seeing a boom offshore where the sector-leading companies such as RXT have figured out the logistics of operating Ocean Bottom Cables (OBC) efficiently and effectively, finally offering the opportunity to realise the potential of multi-component data to delineate 'hidden' reservoirs by imaging beneath gas clouds or imaging reservoirs that are 'transparent' to conventional (wave) seismic and to locate and identify reservoir fluids by yielding rock physics parameters.

OBC deployment offers significant data quality advantages from the use of geophones/accelerometers in addition to hydrophones and from avoiding the noise arising from towing a streamer and from the sea surface itself. Also, RXT uses new sensors that have excellent characteristics down to very low frequencies, crucially important for imaging deeper images. OBCs can be deployed in areas where towed streamers are impractical, for example in very shallow water or where there are obstructions such as producing platforms, moored rigs and so on: also OBC enables a full Multi- and Wide-Angle capability. Obtaining high quality multi-component data and then processing and analysing it has always been seen as something as a challenge in the industry and indeed the latter has always occupied somewhat of an 'academic' backwater in both the Majors' R&D departments and the bigger geophysical service companies. However, it has now moved into the mainstream.

There is significant overlap between the topics discussed above and we could say that 4th Generation Seismic equals Total Seismic, the ability to acquire data at any azimuth, any offset, for any depth, for any geological target and to use massive computing power to process and analyse it. Seismic remains "King" and I recall the advice of my first boss in BP who said "If you have a $100 to spend on geophysics, spend $99 on seismic and the rest on a good cup of coffee at least that is how I remember it!"

Finally, it's worth noting that Total Seismic seems to involve the use of more than one boat; perhaps it wouldn't have taken us nearly seventy years to get there if Shell Oil's 'bean counter' hadn't stood in the way some things never change!

posted by The Rogtec Team @ 12:21  0 Comments

Tuesday, 9 September 2008

Enhanced Oil Recovery

Technology Implementation at Lukoil

Cost of the upstream R&D has focused on developing efficient logging systems, improving methods of estimating reserves (studies have continued on creating methods for calculating hydrocarbon reserves in reservoirs with complex structures), and also on developing and improving methods of enhancing oil recovery and optimizing the development of undrilled areas and reservoirs. Steady attention has focused on environmental protection technologies, especially for offshore fields.

One of the most important results of LUKoil's technology development effort is the active use of methods for stimulating oil production and enhancing oil recovery (EOR). These methods substantially increase recoverable reserves and oil production, and allow commercial development of reserves of highly viscous oil, reserves in low-permeability reservoirs, and hard-to-recover reserves at the late stages of field development. In recent years, the proportion of oil recovered through the use of various stimulation technologies at LUKoil fields has been more than 20% of total production.

In 2007, the LUKoil Group performed 5,292 EOR operations, which corresponds to the 2006 level. LUKoil companies employ physical, chemical, hydrodynamic, and thermal methods to stimulate pay zones. In the reporting year, EOR techniques accounted for additional 23.7 million tonnes, or more than 26% of LUKoil's total Russian production. The bulk of the enhanced recovery (14.4 million tonnes, or 61.3%) was produced by physical techniques, primarily hydrochloric acid fracturing (hydrofrac).

In the reporting year, pilot production using acid frac technology continued at 12 cis-Ural fields. Thirty-one operations yielded an average oil flow increase of 9.4 tonnes per day (tpd), for a total enhanced recovery of 59,000 tonnes. Based on this experience, this promising technology will be employed widely in LUKoil's other oil production areas.

Other EOR techniques (hydrodynamic, thermal and chemical methods, and stimulation of oil recovery) have yielded 9.2 million tonnes. The results of various EOR techniques have shown the high effectiveness of chemical methods in limiting water encroachment in wells. For example, the widespread use of chemical technologies at West Siberian fields has reduced the overall growth in water cut from 2.4% in 2006 to 1.2% in 2007.

The use of chemical technologies more than doubled in 2007 over 2006 (from 494 to 1,004 operations), and the enhanced recovery totaled 1.3 million tonnes.

In 2007, LUKoil tested a new water-alternating-gas (WAG) injection technology on an oil/gas reservoir in order to stimulate oil recovery using a booster unit. Since the technology was introduced in 2005 at East Pereval Field in West Siberia, the enhanced oil recovery due to WAG injection has been 8,300 tonnes, including 3,100 tonnes in 2007. The LUKoil Group plans to extend the technology to other oil production sites in 2008.

Another highly effective EOR technique is the sidetrack drilling from existing wells. The sidetrack drilling expanded in 2007, with a total of 188 sidetracks placed in service (vs. 146 in 2006) with an average enhanced flow of 19,200 tpd. Enhanced recovery totaled 579,000 tonnes, up 17.2% from 2006. The greatest increase was at a group of West Siberian fields, where the average flow increase from 47 sidetracked holes totaled 33,400 tpd, which is practically equivalent to the flow from new wells.

Pilot radial drilling continued in 2007. At relatively low cost, the drilling of radial channels from existing wells permits both stimulated recovery and development of hard-to-recover reserves. The LUKoil Group carried out 39 operations with an average oil flow increase of 8,000 tpd. The enhanced oil recovery produced by this method totaled 21,500 tonnes. LUKoil will use this positive experience of radial drilling in other oil-producing regions.

In addition, the LUKoil Group uses horizontal drilling to increase the efficiency of oil production, raising well productivity 50Р100%. In 2007, LUKoil placed 109 new horizontal wells in service, with an average flow of 65,500 tpd.

The LUKoil Group made active use of new technologies for when drilling and constructing horizontal wells in 2007. For example, data obtained from the drilling of two horizontal pilot wells were used to build a model of a pay zone in West Siberia. During drilling of the horizontal leg, a logging system was used to refine the model in real time and select the trajectory to achieve the best porosity and oil saturation.

At the Usa Field in the Komi Republic, the LUKoil Group performed a smart completion of a horizontal well in a Permian-Carboniferous reservoir where heavy oil is being produced. The horizontal leg was broken into four sections, each of which has pressure and temperature sensors and a device for opening/closing the perforation interval, controllable in real time from the surface. This permits each section of the well to be operated separately and formation parameters to be tracked in real time.

At Yarega high-viscosity oil field (Komi Republic), pilot operations to adapt thermogravitational drainage technology using horizontal wells for secondary steam-heat "huff-n-puff") development of this field have been underway since late 2005. In the two years the technology has been in use, it has shown steady growth of basic development parameters.

Oil production in the pilot production area has risen from 200 tonnes per month in January 2006 to 1000 tonnes per month by early 2008. In 2007, the LUKoil Group developed a program to adapt this technology at a new pilot production area in Yarega Field. Implementation is scheduled for 2008. In 2007, based on analysis of the pilot operations at Yarega Field, the LUKoil Group developed a Method of Developing High-Viscosity Oil Fields, which proposed options for developing fields like Yarega. The technical solution is currently under expert review at the Russian Patent Agency [Rospatent].
posted by The Rogtec Team @ 23:32  1 Comments

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