2012 Spain Sand Control Scribe Report

7/22/2019 2012 Spain Sand Control Scribe Report

1/26

1

SPE ATW "Pushing the envelope in Sand Control"

11

13 September 2012 Barcelona, Spain

The workshop was well attended with 76 attendees mainly from North America and Europe. There

were total of 8 sessions with 25 presentations and 2 open discussions mainly covering challenges,

case studies, and emerging technologies in openhole sand control.

Day 1: Tuesday 11 September 2012

Bala Gadiyar opened the workshop welcoming the delegates. He thanked the committee and SPE for

organizing the workshop. He invited for input for topics of interest for discussion/breakout meeting

and encouraged open discussion. Bala Gadiyar thanked the 5 sponsors.

Bala Gadiyar: 2008 ATW: sand control in long intervals in Florence. The input from 2008 was the basis

for the content of the present workshop. 2008: 96 attendees, with very good open discussion; one of

the best ATW according to SPE ratings.

Session 1: challenging environment : long/heterogeneous interval

The first speaker unfortunately could not be present for his slot due to flight delay and was

rescheduled for Day 2.

Richard Hodge (ConocoPhillips): Sand size variation: no big deal or lurking disaster

Bigger variation in sand size over the years. Sizing criteria: when looking at completion with screenonly, or gravel pack (GP), frac pack, several different methods are used to characterize the formation

sand size. Need to know what size of sand one is trying to stop and the range of variation in sand size

through the producing interval. Different methods of characterizing the sand size are used in the

industry (usually the d50 or d10). To simplify the problem, some use an average d10-d50 values and

some size for the smallest d10 values (being conservative). Both methods have inherent weaknesses

and can lead to poorly designed sand control completions.

Questions & Answers:

When confronted with a very large variation in particle size distribution, it is a challenge to designeffective sand control completions. Basing the sand control design on a single PSD (average sand,

composite sand, etc.) risks oversizing or undersize the retention media. COP conducts tests with

multiple formation sand samples that span the range of PSDs observed in the target interval.

Question: There is a high uncertainty on representativity of cores, when stepping out of the zone

where cores are taken. How does the degree of consolidation matter?

Answer: Eliminate sand with very low permeability and sands with high UCS, so one narrows the

range. Another way is to run triaxial tests and see if there are multigrain clusters produced, but

there will be significant uncertainty in this approach as multi-grain clusters may disaggregate later in

the life of the well.


2/26

2

One suggestion was to just gravel pack, eliminating the smallest sand size distributions from

consideration, and selecting the smallest gravel size. The argument against was there are no

published papers showing how to select gravel size based on a wide particle size distribution (PSD),

outside the Saucier criteria range. Saucier used clean sand with no fines, so the criteria may not holdfor real PSD's. A comment was made that many people would like to use larger gravel, but there are

no studies done showing what is the largest gravel size that can be used without sacrificing sand

control. This was countered by what is wrong in being conservative with gravel size since you will still

have significantly higher gravel permeability compared to formation.

Another suggestion was to perform a series of field tests with different screen mesh sizes tailored to

formation PSD across the interval. This sounds good on paper, however in reality if you get stuck

while running in then you may not have the right screen mesh across the formation.

The concern of small mesh size screen getting plugged by mud while running in was mentioned andrequire stringent practice. Over 200 microns screens are more resistant to plugging. Initially in the

project, started with largest screen opening but had sand production problem as a result reduced the

screen size. COP fills openhole section with solids-free drilling fluid. This was possible due to large

number of wells had to be completed.

There is no single filter for heterogeneous formations with wide variation in PSD in a planned interval

as a result you may have to give up pay for some zones, with blank pipes and focus on the good

zones (look at the logs, not the cumulative PSD). However, it may be difficult to do statistical PSD

variation for the interval since geologist may already have weighted the distribution by cherry picking

the cores.

When selecting the completion type of heterogonous formation it is not as simple as just looking at

the PSD but also should consider expected production rates (velocities can mobilize small fines) and

drawdown on sand face. One can relax sand retention rules for low rate wells but not for high rate

gas wells.

Colin Jones (Chevron): Management of Produced Solids

The approach of modeling sand production and managing produced solids has led to huge savings for

Chevron not using expensive completions, especially for deep offshore fields. Sand production: a lot

of physics not fully understood, different failure modes etc. sometime one predicts sanding but it

does not occur due to arching, etc. Higher productivity if some sand is produced, but must plan well

for completion to minimize erosion problems etc. Chevron has been putting effort into volumetric

sand prediction. The goal is to maximize NPV. Onset of sand prediction is very conservative; need

sand transport to get sand topside. Tests show that single phase hollow cylinder tests produce more

sand at higher rate, compared to Swi (oil or gas) tests, even though onset stress is comparable.

Chevron's FEA simulations capture laboratory observations of rock failure pattern.



3/26

3

Question: Expensive completion and sand management might be more costly than installing sand

control.

Answer: Uncertainty in sand prediction, one must manage risk correctly, on most wells one must use

sand control, but for some of them one will save a lot of money by not putting in SC.

Question: Economic considerations should come first. What is the cost of one failure due to a wrongprediction? For subsea, always use sand control unless sure the rock is very competent. Is the core

representative of the whole reservoir? Can one afford the risk?

Answer: Agree, but worthwhile process to investigate, cheap in comparison with savings.

Question: How does Chevron upgrade the results to send feedback to facility engineers?

Answer: Sand production over time for production strategy is handed over to the facilities. At the

moment this is only a research project.

Question: How is the near-casing area? Is there a cavity? How does it affect casing stability?

Answer: perforations may connect and a large cavity forms behind the casing.

Question: Model looks only at one perforaton, not at the interaction between perforations.

Answer: models show cavity formation. Have data from a field producing a lot of sand, showing that

there is a cavity behind the casing.

Question: Do the outcrops used contain shale?

Answer: 100% sand (Castelgate outcrop) is used in the tests.

Question: Thin slots, wormholes as seen in some tests are different from a regular cavity, not

captured by FEA simulations?Answer: not known.

Question: When predicting volumetric sand production, right order of magnitude is required.

Confident that Chevron gets right order of magnitude?

Answer: Chevron does better than that.

Session 2: Challenging environment: HPHT

Allan Twynam (BP): BP Skarv developmentSnadd north OHGP

Challenging project to design but very well executed. Fluids design for the project was critical due to

highly reactive shales. The completion objective was to test reserves and productivity of reservoir.

Quality of sand was well sorted with Darcy permeaility. About 60 % sand, a lot of shale present, and

PSD required to design a horizontal OHGP. This was BP's 1st

OHGP in Norway. In OH, the reservoir

drill-in fluid (RDF) must be properly designed for good clean-up. The main focus was on shale

stability issues with gravel pack carrier fluid. Cesium formate brine was selected as gravel pack carrier

fluid as it was compatible with the shale where there was no swelling or fracturing. Due to reactive

shales, the well was drilled with oil based RDF. The screens were RIH in conditioned mud. Gravelpack efficiency was 80% and no losses were reported.


4/26

4


Question: Is there a standard test for shale dispersion?

Answer: Common when no core material is available, with 10 gm of cuttings, forming chips, expose

them to fluids for 16 hours, dry cuttings and weigh (missing weight has been dispersed. Prefer

swelling test on core; BP is developing it further to be under confining pressure).

Question: Not aware of any standard on mud conditioning (is there a BP standard?)

Answer: Experimented with larger mud volumes than service companies would do.

Comment: Plugging occurs in screens long before the pressure builds up and depends on particle

concentration.

Question: BP decided to move to GP away from SAS, what was the criterion for that?

Answer: George King and BP guidelines for PSD analysis are based on: fines content (sub 44 microns)

and relations between D10/D95, etc. The main reason for GP decision was the wide distribution

between clean sand and clay rich sands.

Question: Was there formate corrosivity on screens in 6 month shut-in?

Answer: Had planned to use corrosion inhibitor, but were in unknown territory with whole year shut-

in. Lab testing was done for 6 month exposure, showing that it was OK.

Question: What standard is used, weight loss for corrosion, is there no industry standard?

Answer: BP does not look at weight loss but looks at sand retention change (i.e. change in screen

mesh size).

Question: In overpressured reservoir, frac window gets narrow, how is it addressed?Answer: Had very high frac gradient, not an issue for this particular project.

Question: choice of GP technique?

Answer: Peer review looked at well length, net to gross, how well was the shale behaviour predicted,

so BP was confident there was no need for alternate path technique.

Question: what were the gauge sizes used?

Allan Twynam: Used one size smaller than test size.

Question: What compatibility tests were conducted?Answer: Series of tests where fluids at various ratios are mixed from 100% mud to 0% mud, not

looked at through screens, just measured rheology at different temperatures.

David Lowton (Total): Sand control challengeHild (Martin Linge)

Complex field. Wells drilled with jack-up platform. Gas condensate to be sent to UK. Heavily faulted

east field. Challenges: narrow mud window in reservoir, HSE well control and integrity. Plan is OHGP

so challenging if fractures are induced. Will have OH shale above reservoir that cannot be cased due

to geological uncertainty. The design of the cement job is critical (integrity issue for confirmed

barrier). Elastomer tests are run to address material compatibility with cesium formate fluid.



5/26

5

Question: why were SAS rejected?

Answer: Due to high production rate and the presence of shale interval which could swell on the

screens.

Question: High risk of early sand failure or delayed risk?

Answer: East panel most sand prone, formation becomes stronger in central and west panels. Theywill produce sand at some point in the field life.

Comment: One could potentially complete enough such that one can come later with new wells as

depletion incurs.

Response: 3 zones isolated by shales, so differential depletion will be seen but unsure where it will

occur. Might be impossible to drill later on.

Question: Any study on PI impairment of stress caging material?

Answer: No studies done, need to do it.

Question: MPD for drilling; considered MPD while placing GP?

Answer: Have not up to now, still looking at feasibility.

Question: Is WBM going to be used for drilling?

Answer: Not sure.

Question: How to deal with shales? Cs formate: is there any alternative?

Answer: OBM which would require weighting up and can lead to barite sagging, had 30 m of sag on

top of reservoir, so have not found any alternative.

Question: Have you looked at expandables?Answer: This is the contingency, but not base case due to how much deformation is allowable before

failure, is border-line, but a possibility for further wells after some onset of depletion.

Hvard Kaarigstad (Statoil): Evaluating and reducing operational and productivity risks for OHGP in

HPHT environments

Statoil thoughts on OHGP feasibility. Traditionally tried other solutions in HPHT, not GP, but maybe

should be considered.


Question: why not use frac packs? Many done in same scenario.

Answer: Not widely used by Statoil, could be a solution, definitely, must get more comfortable with

technique.

Question: How do you do well control after FP. Are there many vertical SAS wells?

Answer: Not excluding horizontal wells but near-vertical is chosen.

Question: What is the current limit for frac pack, 2 SG seems high?

Answer: Temperature and pressure are similar to other frac-pack cases.


6/26

6

Question: Were the other SAS high angle and this is why Statoil is hesitant?

Answer: Norsk Hydro had an extensive experience with SAS with good production but taking this

experience to new fields brings issues that make Statoil reconsider this technique.

Question: Some BP fields are very similar to this one. Yard testing: is the test program ongoing?

Answer: Yard testing has just started, fine-tuned these days. Done by one of the service providers.

Question: We are working on HPHT GP as well, but at high angle. Compatibility with Cs Formate, is it

solvable?

Answer: No systematic testing with high temperature brine exposure on filter cake done yet. Should

do static and dynamic testing, where after a couple of days, fluid loss to the formation is monitored.

Session 3: Open Hole Challenging environment: low fra gradient / depleted

reservoirs

Ron Rock (Shell): DIF and breaker/stimulation fluids designs for OH low frac gradient environments

Challenges coming up with severe depletion. 716 ppg fluids in depleted reservoirs, up to 400 deg F,

so broad spectrum of weights and fluids. Depletion between 10008000 psi in the reservoirs.

Number of projects could double to 10. All applications here are OH, other teams deal with cased

hole. Lower solids loading leads to lower ECD and lower clean up density fluids. Problem identifying

differential sticking in high OB conditions, no testing capability found.


Question: LCM fluid?

Answer: Try to have stimulation fluid designed into the program, have field experience treating

particles beyond 250 microns.

Question: What about stress caging fluid treatment?

Answer: Need to make sure you have particles that are acid soluble or cleanable by the LC fluid

designed. Primary objective is to have stimulation fluid available. Will try to drill with PST quality

fluid, if not possible will design cleanup fluid to address issue.

Question: Putting GP in place on top of coarse mud?

Answer: Have only lab experience. There are some fields with thief zones where all types of LCM

particles were used and successfully ran screens and GP on top of it.

Mehmet Parlar (Schlumberger): Solutions for OHGP in low frac gradient environments

OHGP can be performed in low frac gradient environments. Presented both mechanical and

chemical options that can be either used as a standalone or in combination of depending on well

conditions. Light weight gravel helps reduce friction (due to lower pump rate) both in alpha and beta

waves while diverter valves only help during beta wave. Friction reducer which is added to the carrier

brine helps reduce friction for both alpha and beta wave. Another technique called/packing you

form multiple alpha waves by reducing rate for each alpha wave; with this technique you do not


7/26

7

achieve a 100% pack efficiency; the goal is to cover the screens and expect wellbore collapse to form

a natural pack. With alternate path technique, one can eliminate the washpipe and reduce the

pressure on the sandface. Highest number of diverted valves used in an actual completion is 8 by

Chevron.


Question: How does one get the mud out?

Answer: Could do like ExxonMobil, reverse circulation.

Question: Diverter valve offers benefits, splits mud returns avoiding them over one spot. Running in

hole, advantage of washpipe, one does not take mud returns in the screen.

Answer: Should have conditioned the mud.

Question: Has the diverter tool been used with shunt tubes?

Answer: Yes, in Brunei, run in clean fluids.

Vladimir Bokharev (TAQA Energy): Sandface completion for UGS wells in highly depleted reservoirs

UGS in highly depleted Bergemeer field, with 2 sandstone formations. No conclusion on formation

strength rebound upon repressurising: go for worst case. Favorite option for durability was GP but

was going to challenging from deployment standpoint. CHGP did not meet productivity targets.

Service providers could not offer acceptable solution to install GP, so it was abandoned. Stand alone

screens (SAS) were selected as the best completion option based on the ease of installing and

meeting productivity targets.


Question: What can be done for screen remedial?

Answer: Can straddle erosion spots from inside. May have to side track.

Question: Impairment of productivity for OHGP compared to SAS is based on what? How can it be

explained?

Answer: Based on simulations, surface pressure. Comment: OHGP PI should be same as SAS.

Question: What was equivalent fluid density at static conditions?Answer: Up to 0.6 ppg, that was the challenge.

Question: how to swell packers in dry gas?

Answer: Well will be displaced to WBM.

Comment: Water could invade formation if the FC does not hold the water on the swell packers.

Question: Dry gas can suck out the water from the swell packers. Could use oil swell packers.

Answer: Swell packers not used for stringent zone isolation, after a while, formation collapse will

occur.


8/26

8

Question: SAS consideration different for injector and producer in vertical well. No concern for SAS in

low angle well?

Answer: No.

Question: 1ft/s?

Answer: Usually 5 ft/s but design was conservative due to lack of UGS experience.

Question: Will run SAS in well partially filled with mud. How is the mud tested?

Answer: Will be tested under MPD conditions.

Brre Fossli (Ocean riser systems): The use of managed gradient drilling technique. Potential

benefits of GP in depleted or low frac reservoirs

Possible to control BHP much more efficiently now. A control system manages the fluid level in the

riser by activating a pump, thus reducing the gradient when needed to keep the BHP constant. Indrilling and running in of completions, the system can compensate for the ECD and bring the sand

face pressure below frac.


Question: Is there a possibility to bypass the system? What about reverse circulation for GP screen-

out?

Answer: Not a problem once the reservoir is isolated.

Question: many GP tools need hydrostatic pressure by design. Is this device approved by regulatory

authorities?

Answer: Approved in USA, Norway and other places, have to work with authorities on well control

and procedures, but depends on use. Issues come when the fluid is so heavy that it cannot be taken

all the way up, but there are procedures. For GP with known pressure, it is much easier to deal with.

Question: in static conditions, the pressure gauge is the only kick detection?

Answer: Kick detection surprisingly much quicker with this system, only half a barrel necessary to

detect. Very accurate flow measurements in addition to the pressure sensors.

Open discussion

Question: How to deal with post-perforation pills.

Answers: HT with complications of WBM and viscosifiers. One-trip techniques are emerging. May

have to get out of WB viscosifiers. Challenge: knowing what the current limits actually are, where is

the gap?

Question: Definition of fines?

Company A: Under 44 microns, but mobile. Dolomite fines can interact with hardware.

Company B: Do not believe in 44 microns, but particles moving in pore space. Also, is it going to plug

or come up to the surface?


9/26

9

Company C: No reason to have a size cutoff. But need to set up a higher limit. If the formation is

failing, are the particles fines?

Company D: Fines should be able to flow through the gravel.

Question: Has anyone tried to change screen mesh size to address heterogeneous formation?

Company A: No.

Company B: One operator tried to have different screens for different formations, but got sand

production.

Question: Compatibility of Cs formate with OBM cake: how fast does the cake break?

Company A: Have used Cs formate to break cake. Testing showed that internal filtercake would stay

in place and was an issue, but maybe high density formate would tackle this as well.

Company B: Ion exchange is going on, a lot of chemistry happening, may alter the internal phase of

the OBM to address that.

Company C: Can use any formate as internal phase to lower the cost.

Question: what is acceptable return perm upon filtercake clean-up?

Company A: the highest one can get.

Company B: Are the lab results validated in the field?

Company A: Typically 80 % return perm is acceptable, since skins can be 10 to 25 times higher in the

field.

Company B: Depends on original perm. High rate gas can take a lot of damage without lowering the

productivity. Tight gas can be killed by slight FD.

Company B: what matters is the skin factor, which is dependent on invasion.

Day 2: Wednesday 12 September 2012

Session 4: ICD (SAS or GP)

Francisco C Gutierrez (Repsol) & Aaron J Bonner (Halliburton): First installation of an autonomous

ICD in South America

The presenters gave an overview of the AICD tool. Oil field situated onshore Ecuador in the middle of

the Amazon forest, with a strong challenge in producing with 95% water cut. The development

strategy is to minimize impact on the fragile environment. Key challenge: water control. As the water

cut increases above 30%, the AICD senses the water and increases the pressure drop, thus restricting

the water influx. This works well for water coning situations but is challenging if the water front is

homogeneous. Still early days of implementation.


Question: Did the tests used emulsified fluid?

Answer: Yes, to ensure good mixing.

Question: Is the tool acting as a separator?


10/26

10

Answer: No, not a separator, just sensing the viscosity of the emulsion and restricting the higher

viscosity emulsion.

Question: Is there an emulsion entering the device in Ecuador?

Answer: Yes, there is an emulsion that has to be demulsified. The oil has a viscosity of 60 cp, the

emulsion is 200 cp.

Comment: Water cut usually forms a good emulsion.

Question: Are PLT's run?

Answer: Yes. The tool is working, since a high skin value is reached.

Question: The tool worked only for 120 days, did production cover the installation expense?

Answer: This was a test, so the next well will be better selected for the tool.

Comment: Had there been a PLT prior to the test, the well would not have been selected, but the

tool still functioned even though it seems the water profile was homogeneous.

Bryan Stamm (Schlumberger): A novel technique for wells that require GP for sand control and ICD

for managing water encroachment: case histories from Ocelote field in Colombia

Field located near Venezuela border. ICD nozzles ensure no viscosity discrimination. ICD installation

was based on log-derived permeability profiles. Original production curves showed rapid and

dramatic drop in production rate. The wells required gravel pack as a result the first trip was an

alpha/beta gravel pack followed by a second trip where an inner string with ICDs was installed. ICDs

resulted in water cut reduction and a good oil production boost.


Question: Is the screen a direct wrap?

Answer: Mesh type screens with perforated base pipe, so no true radial flow. Debatable whether

swell packers would provide complete zonal isolation.

Question: PLT response: was it run inside the control string?

Answer: yes, not run prior to installation of inner string.

Question: is the PLT really a static measurement?Answer: yes.

Question: Are there results from nearby wells without ICDs?

Answer: Looked very similar to simulations.

Question: Issue of isolation: is the operation modeled to reach a conclusion on installation of swell

packers?

Answer: Ran simulation of pressure drop with ICDs, annular flow through the GP. Was not 100%

isolated with GP, but far better than just screen. Netool used for simulations.

Comment: SAS with ICDs, the screens lasted for one year, so surprising that a neighbouring fieldwould use GP with ICD.


11/26

11

Question: how many seal units were run in?

Answer: 3 to 6 PBR's, running multiple seal units. Common technology, all units the same size, no

difficulties getting them in.

Comment: Wells with SAS had no zonal isolation, mixing of shale with formation sands caused

plugging, not small diameter opening.

Question: Any update on well since last year?

Answer: Data is probably available, will follow up on it. Integrating the GP with ICD: the technology is

not mature yet, cost effective for customer.

Question: Are there blanks outside the screen?

Answer: Screens run across the whole interval.

Question: Do we need to run blanks

Answer: In this case, no long sections of shale, different where zonal isolation is necessary.

Question: how many ICD's per section?

Answer: some sections, couple of 100 nozzles, were spaced with Netool. The diameters were chosen

to minimize annular flow.

Joachim Tro (Statoil): First OHGP of ICD screen for Statoil Heidrun field

Three ICD screen intervals placed on 140 m of formation, with sacrificial screens at heel and toe.

Well deviation was approximately 70 deg. Did not achieve a complete pack.


Question: Was modelling done to avoid fracturing?

Answer: yes, fracturing was not an issue. Get split flow after sacrificial section.

Question: why choose to run in WBM and then change to brine?

Answer: Believe that no plugging would occur, had conditioned mud.

Question: Wellhead configuration, was it single annular screen?

Answer: Extra annular barrier with dual.

Question: why GP instead of SAS?

Answer: Last jobs in Heidrun were with GP.

Comment: GP of blank pipes, analyzing several jobs in Heidrun, some of the blank sections are 500 m

long between 2 screens. Seen several times that pressure looks like two alpha, with flow split and

pressure jump staying flat and the beta wave generates a new alpha on top of the first one, the beta

acting as a choke at the heel. This is the reason for having the sacrificial screen. Pumping for 15 hours

usually while here only 4 hours. Not 100% packing efficiency.

Comments: No more than alpha type packing in tests. Would be an idea to install more gauges.

Question: Are the ICD's placed towards the toe when running in?


12/26

12

Answer: No at the heel.

Question: Sacrificial screens are isolated after GP?

Answer: Yes.

Question: what was the frac gradient of the formation, how much margin was there?Answer: Do not believe any fraccing occurred. Were monitoring the returns.

Comment: The well is just deviated and gravity helps.

Session 5: Cased hole multizone completions

Nick Clem (Baker Hughes): Refining frac pack tool erosion prediction

Qualifying of tools is done on full scale test. Changing variables is not possible and supplementary

smaller scale tests are run. It is difficult to correctly simulate the downhole flow regimes, with

consequences for proppant erosion of the tools. The new feature of the coupon erosion tests was

using realistic flow velocity for a frac pack. Tests show that different brands of proppant give

different erosion, probably related to particle shape.


Question: Single strike or multiple hits in coupon tests?

Answer: Single strike.

Question: Was different proppant specification responsible for different performance?

Answer: On paper, all proppants are the same, so no internal QC available yet in Baker. Have taken

this issue to the vendors.

Question: comparing same specs proppants, differences are seen, but what about different specs? Is

it worth going for high quality proppant?

Answer: Not sure about what quality means, have not compared i.e. high sphericity with poor

sphericity.

Question: No industry standard looked at surface quality of proppant, since not important for

fracturing. In HR frac jobs, erosion happened very fast.

Answer: Applicable more than to tool design.

Question: With abrasive jets to perforate, one goes away from smooth particle surface to facilitate

abrasion. The more angular the sand, the more erosion one gets.

Answer: in Baker tests, the sphericity was on purpose identical, but surface finish varied.

Question: Proppant flowback, is something missing in qualification of proppant? Only occurring at

very high velocity?

Answer: Variables are interconnected, i.e. angle of impact has a large effect on varying the difference

between the different brands.


13/26

13

Question: Particle size and shape and concentration are difficult to simulate with CFD. Is Baker

looking at size effect?

Answer: there is a lack of data for CFD to tackle the size effect, more coupon tests will help.

Question: Cheaper is not always worse?

Answer: no.

Question: Operator interested in proppant permeability, not erosion unless things go wrong. How

many tests were done to reach the conclusions?

Answer: Not yet in statistically relevant range (5 to 10 tests) on some tests. Not sure what the impact

of brand is on conductivity. The conductivity for all brands was chosen to be the same (as specified).

Question: What impingement angles are expected downhole, since this has a large impact?

Answer: The CFD tool will bring these answers. The first stage was to improve the accuracy of the

erosion prediction.

Question: How would be the uncertainty due to reproducibility?

Answer: 5 to 10%.

Comment: Material science aspect. Much can be done by using better materials (pump seats etc.),

technology of impregnation of synthetic diamonds, for example, could look at improving the tool

material rather than the proppant finish.

Response: Proppant aspect was a surprising result of a study looking at new materials.

Tony Bernardi (Shell): Single trip multi zone sand control

Some issues occurred in first uses of STMZ tools in 2005. Brunei has small blocks with small reserves.Multiple completions had sometimes sand control only in the upper zones. Single trip system allowed

going for small reserves economically. The different zones have different lengths. The more zones

there are to treat, the more savings in operation time compared to stack and pack.


Question: Is it possible to frac with 0.5 inch clearance?

Comment: Inner clearance is a compromise, in some cases 0.75 in is enough to frac. 0.5 is definitely a

challenge. Another challenge is differential depletion.

Answer: Be able to set all packers at once was important in Brunei to avoid cross-flows. The rate perzone was not very high.

Question: Are there guidelines for avoiding frac?

Answer: 500 psi in this case.

Question: Was a perforation cleanout run done?

Answer: Yes, single trip for placement, single trip for cleanup.

Question: For small zones, 0.5 in is not a problem, but the distance between zones was min 40 ft,

difficult to deal with. If a problem occurs, is it possible to pull out?

Comment: One can close a sleeve and shut off an interval. Did not try to pull out.


14/26

14

Tommy Grigsby (Halliburton): sand face completions enter the real time age

Today's wells where sand control is needed are getting deeper with increasing deviation and longer

completion intervals. Difficulty in locating placement of sandface completion. Real time visualizationallows one to see the completion and its movement. Preplanning with the tool helps seeing where

the shifters are for given jobs.


Question: Can one return to use generation 1 tools with the RTV?

Answer: Would have to set-up configuration to utilize with Gen1.

Question: Are there any sensors placed downhole?

Answer: No, but the tool is as close as possible to real-time.

Comment: Doing more downhole with single trip, but not necessarily the philosophy of all operators.

Question: Computer system helps operator, but they can be reliant on what they see on the screen;

if program is wrong, there could be conflicts.

Answer: Tool operator judgment is preferred at this time, may change with downhole sensors. Just a

support tool.

Question: Can the tool make calculations for the operator?

Answer: Long term capability will be there. Gives weight on tool.

Question: Challenging Deep Water is an opportunity for new technology, real time telemetry is

needed, see downhole pressure and T, and see tool. Should be real-time data.

Answer: Must take care incorporating sensor technology without jeopardizing the tool operation.

Question: Preferred telemetry systems?

Answer: Must downsize tools but looks doable, even with pump noise. Data transfer now at 40 s

from tool to rig floor.

Agostinho Calderon (Petrobras): HOHGP in Petrobras

Campos basin fields are 100 to 140 km offshore and water depth is more than 1000 m. Horizontal

wells are a good option for sand control, considering the high productivity. Wells are drilled with

SOBM and openhole with WBM. The openhole gravel pack technique is alpha/beta and in most

cases the frac pressure window is narrow. Openhole length varies between 100 to 1200 m. To date

352 wells have been completed with no sand control failure until one well failed in July 2012.

Strategies were presented to deal with the narrow frac pressure window such as light weight

proppant, lowering carrier fluid density, open BOP configuration, friction reducer, etc.


Question: The red line minimum rate is changing between the different simulations?


15/26

15

Answer: Changing the proppant weight reduces the red line, since it is easier to transport the

lightweight proppant.

Question: Does not address losses during the GP operation, can return rate be calculated?

Answer: The return rates make a good GP, so it has to be put into the simulator or monitor losses.

Simulation is done before the operation, together with circulation tests to check the pressures andput again in the simulator. The new operational window is used to design the GP job. The service

boat has many types proppant, such that last minute changes can be done. It is easier to stay

towards the top of the operational window, if fracturing occurs, the pump rate will be reduced

immediately sending new alpha waves.

Comment: This is alpha alpha wave hoping to get a return beta wave.

Question: How does one calculate the frac pressure for the window?

Answer: Determined from all the wells and by analysis of the WD and different formations in place.

Can be corrected during operation, since loss of return indicates losses. Sometimes, an FIT is made.

Question: Are most of the wells completely packed?

Answer: Packing efficiency is normally calculated with acoustic calipers. Must check pumped volume

but not very accurate. Results show that more than 70% packing efficiency is good enough, for 8% of

the wells it is below 70% and they have SAS bean up procedures.

Question: Could SAS work?

Answer: Petrobras experience is not good, with sand production, even though there was low fine

content.

Question: Are the screens designed to stop sand?Answer: Yes, based on the d50 of the formation sand.

Question: The screens are always on the bottom, how does one account for absence of GP below the

screens?

Answer: Not a problem not to use centralisers. One avoids formation movement this way as in ESS.

Question: Surprised that there are no problems drilling such long intervals. Any procedures for

filtercake removal to ensure proper production?

Answer: Normally, not necessary to treat filtercake. In injectors need acidizing.

Session 6: Sand screen emerging technology

John Weirich (Baker Hughes): Sand management system using morphic shaped memory polymer

technology

The new technology is a trial to reproduce GP benefits with easier deployment. The material is

expanding at a transition temperature getting softer but exerting force on the wellbore wall. The

material is heated to be soft, compressed and cooled to remain rigid and compressed to be inserted


16/26

16

into the well. An activation fluid is applied downhole to lower the glass transition, making it soft

again and swelling. The activation fluid is removed, Tg increases and the material regains its strength.


Question: Is there a way to tailor the foam for different PSD of sands?Answer: At the moment temperature limited to 60 C. Some going at higher T may have different pore

structure and are under development.

Question: Applications?

Answer: 6 trials done, some problems such as low tensile strength with burst upon run-in.

Question: Rated for sour environment?

Answer: Yes, has been tested with H2S, CO2and has shown to be inert.

Question: How does the material fail mechanically?

Answer: In the rigid state would be brittle.

Question: Any triaxial tests of material for brittle ductile characterizing?

Answer: Not known that it has been tested. Tests showed that the material crushed on load but

recovered afterwards.

Question: Activation fluid: how does one ensure contact?

Answer: Best to ensure AF contact both on OD and ID. Fully expanded: 4070 Darcy, fully retracted:

4 Darcy.

Question: What is the max OD?

Answer: Opens up as a function of how much material is manufactured.

Question: Filtercake cleanup and LCM in place before running in?

Answer: Yes.

David Noblett (Darcy): Do today's sand control solutions fit tomorrow's envelope?

No new sand control technology has emerged after the ICD and ESS innovations in the 1990's. The

new Darcy screens build on existing base pipe and screen technology but add activation chambers

that ensure centralized placement with positive compliance.


Question: Filter medium, what is the seal when growing in diameter?

Answer: There is substantial overlap to maintain integrity upon activation.

Question: Any stresses on the mesh?

Answer: Some stresses develop but can overcome them.

Question: Is there non-compliance across the connections, where support of wellbore is lost? Wire

Wrapped screens plug less easily than weave; with large solids content in mud, is there any work

done to avoid weave plugging?

Answer: Up to 1.5 sg, works well since a breaker can be circulated in the non-activated state.


17/26

17

Question: Qualification done on 2 casing sizes, but the inflation tubes run lengthwise, what happens

when the wellbore diameter changes or the hole is not circular?

Answer: Ovality up to 1.1 is OK; step diameter 8.5 to 9 7/8. OK even if not compliant on a small

section where the change happens. Scalability is not a difficulty.

Question: Can one choose an entirely perforated base pipe?Answer: Looking at that. Limit on OD is 10 in, if hole is greater than 10 in the limit is set at 400 psi.

The system can be used as a SAS in worst case scenario where formation collapses all the way.

Stefanie Wildhack (PetroCeram): Ceramic sand screens: a novel approach to sand control

11 applications have been deployed with ceramic screens. The motivation for the development of

the ceramic screens was erosion-corrosion problems at Mrsk. The ceramic material is acid and

temperature resistant. The problem was brittleness with low tensile strength, so the final design

builds on compressive deployment, since the compressive strength is much higher.


Question: How do the screens handle H2S?

Answer: No problems.

Question: Were the wells vertical in the SAS application?

Answer: Yes.

Question: 3 modules placed together, what is the maximum length? HPHT applications, if the base

pipe lengthen under Temperature increase, how do the rings resist?

Answer: At the moment no more than 5ft to ensure good compression overall. In the endcaps there

is a spring loading system, allowing for removing or adding 2 rings, due to difference in expansion

coefficient between ceramic and metal.

Question: What is the limit on the gap width?

Answer: 100 micron without machining, tolerances are similar to Wire Wrap.

Question: Any crushing, point load tests?

Answer: Yes, all tests are positive.

Question: What is the function of the shroud? It is not erosion resistant.

Answer: Mechanical strength for protection of ceramic.

Question: what is the material of the spacer?

Answer: Also ceramic. The material of the end caps and base pipe has to be chosen to resist the

environment of the well. The OD is larger than traditional screens.

Question: What is the radius of the Keystone shoulder?

Answer: 0.2 chamfer to avoid tensile stresses at the sharp edges.

Question: Is it strong enough to be rotated down to bottom?Answer: Yes, it is possible.


18/26

18

Question: Any assembly bending tests?

Answer: a dogleg of 5 deg per 100 feet was OK, new test in October.

Question: The rings are not glued to the basepipe?

Answer: depends on application, can be welded on base pipe.

Question: The gaps could make the screen susceptible to compression failure.

Answer: Ceramic screens are supposed to be strongest in compression, but this has to be tested.

Aaron Bonner (Halliburton): Compliant technology: design and testing of a swellable screen system

The product is designed with spacing manifolds, doubling as centralisers. The kidney shaped louvers

are such that they maintain open flow space even when fully collapsed. They are mounted on pistons

pushing out to support the borehole upon swelling of the rubber.


Question: Installing the screens swelling in unconsolidated formations, could sanding interfere with

swelling?

Answer: Concept is the same as using a swelling packer. Need maybe to pump diesel.

Question: Advantages of ESS is saving time and money, but waiting time for swelling leaves one with

a SAS risking annular flow, should wait 2 weeks before putting well into production?

Answer: Some operators are willing to wait while doing upper completion work (8 days), addressing

issue to shorten time.

Question: if with time dry gas flow comes, is the swelling still there?

Answer: This is a nonreversible swelling process, so no problem.

Question: With gas, the water swell would be removed?

Answer: looked at since water swell seems to be reversible.

Thursday 13 September 2012

Session 7: OH zonal isolation

Mike Barry (ExxonMobil): Alternate path OH packer providing true zonal isolation in OHGP

New technology developed with 9 shunt tubes located around basepipe and below screen wrap

coupled with openhole mechanical set packers. Packers set before gravel packing to ensure true

zonal isolation. Packers are qualified to set in 10 3/8 hole and up to 11. New design allows

extended packable lengths. Alternate path packing is effective in low frac margin areas. Screens and

packers have been run in 3 wells to date.


19/26

19


Question: Is there a manifold area at connections?

Answer: Conventional connection, coaxial sleeve, makeup from one joint to the next with radial gap

(manifold). Slurry flows through the manifold and can divert to one of the 6 transport tubes or 3

packing tubes.

Question: How does one actually pack, where is the exit point from screen how is the sealing of the

exit point?

Answer: 6 transport tubes and 3 packing tubes, with nozzles rings placed 6ft apart. Nozzles attached

only to packing tubes. Slurry exits nozzles at the nozzle ring.

Question: Could you use swelling packers for isolation?

Answer: potentially but depends on asset needs. True zonal isolation needs packerto set prior to

gravel packing. Packer setting is verified through mechanical indication, signature after packing.

Question: multizone stack: does it allow to frac and pack at the same time?

Answer: original goal, but for now can frac top zone and pack others. Cake removal for now not

necessary, cake pinholing upon backflow with +1, +2 skin, without any stimulation.

Question: fluid programs for multizone, displace sequentially fluids?

Answer: drill well with NAF fluid, run screens to bottom, set GP pkr, sweep mud in OH with clear GP

fluid, pushing DIF out of OH, leaving Xanthan fluid in place. Pull service tool up, dump the seals, space

out shifting tools to set the openhole packers, then go back into position and go ahead with GP.

Question: why Xanthan gel?

Answer: evaluated VES but VES breaks with hydro-carbon contact, so use inert Xanthan.

Question: centralizing system?

Answer: at top and middle of every joint.

Question: gas shutoff: qualification tests for gas coning down, can you successfully shutoff gas?

Answer: isolation packers should hold. Gas has to pass through 2 fully packed tubes. Analytical work

shows that gas can penetrate but would then gently flow, Darcy linear flow, across 12 ft.

Question: comment on jetting effect of packing tubes on formation with sand mixing?

Answer: oriented at a pitch doing spiral flow, can do near wellbore erosion but impinging velocity

low.

Tony Bernardi (Shell): OHGP of fishhook wells with zonal isolation

Drill from shore underneath reservoir coming up through it (fish hook) in Brunei since field close to

offshore. Would have been more expensive to drill offshore. 33 completions. Initially had issues with

alph/beta packs in 120-130 wells. Pumped some jobs out the toe and used diverters in washpipe

on other jobs. Used low density ball to set gravel pack packer.


Question: possible to pack 1600 m potentially?


20/26

20

Answer: based on scaling of pressure. Exxon estimates based on Xanthan while Shell use VES low

friction with lower sand loading.

Question: drilling out then coming down evaluated to avoid coming up (so as to drill standard

deviated wells and not having to GP upwards)?

Answer: difficult to do from borehole stability consideration.

Question: fast swelling packers?

Answer: Used accelerate fluid to swell packers in 15 hrs, detected by difference in pressure at the

gauge.

Question: how long were the intervals treated?

Answer: 400 m.

John Weirich (Baker Hughes): wellbore isolation

Overview of techniques available. Swellable packers limited by available time to wait for swelling.

Running swellable packers in blank pipe section inside casing to help isolate MCS.


Question: testing packers, how does one test for OH conditions?

Answer: looking for absence of returns. Can also pressure up port between elements.

Question: testing in lab for OH? Borehole failure due to packing?

Answer/Discussion: there is some discussion about initiation near packers in shales, not known if thisis an issue. Exxon packer was cycle tested in casing. Also set packer in low UCS cement. Microseismic

interpretation showed frac just in front of packers but this was not a swellable packer. Very

important to place them correctly for long sealing time. There is an initiative to ISO qualify packers,

based on casing testing.

Session 8: Life Cycle management

Andy Duncan (Weatherford): Using zeta potential altering chemistry to increase maximum sand

free rate

Consolidation method where one takes the zeta potential of sand grains closer to 0 to have them to

agglomerate. Studies show that the injected chemical does not stay in the pore volume but adsorbs

to the grain surfaces, such that permeability is unaltered and many treatments can be made

sequentially. Very promising for fines control. Promising in consolidating sandstone and hindering

sand production post failure. 170 wells treated so far with 90 % success.


Question: Is this chemical normally associated with acidizing post-treatment?


21/26

21

Answer: do acid placement prior to treatment but not after treatment since it can remove the ZPAS.

Question: mentioned fines production in SAS scenario; Some want the fines to be produced, with

facilities ready to handle them.

Answer: in the cases cited, the facility could not handle the fines.

Question: During analysis of ZPAS, were control fluids also tested, such as water flush to push fines

away and compared?

Answer: Zpas flushes fines outwards as other fluids but they conglomerate there and do not flow

back.

Question: is this one time treatment or does it have to be retreated?

Answer: depends on flux rate that could strip off chemical and chemical environment.

Question: how do you identify good candidates for treatment?

Answer: get sample of formation sand, do XRD to quantify shales, look at logs for clean sand

intervals, look at perm porosity contrast, treat up to 160 ft with brine, beyond that need to viscosify

the fluid such that it gels in place with further fluid diverted further along the interval to be

consolidated.

Question: is it toxic?

Answer: no, approved for use in North Sea.

Question: how deep is the chemical penetration?

Andy Duncan: treat 3 ft out with 3 PV, depending on formation permeability and chemical

concentration.

Question: how much can it be assimilated to colloidal system (solids dispersed in liquid) while here

we have liquid dispersed in solids?

Answer: treated gas and condensate, stepping into heavy oil, not sure about chemistry details, but

tests show change in zeta potential and agglomeration.

Question: have looked at resins, what is the advantage?

Answer: previously looked at resins, gluing grains and impacting negatively permeability. With

depletion, get broken bonds irreversibly. ZPAS has no glue, so is ductile.

Ed Leung (Resman): Enhancing ICD & OHGP completion by utilizing wireless reservoir surveillance

technology

Need to mitigate completion installation risk, but there is resistance to run cabled equipment and

electronics of sensors is not reliable. Risks of compromising packer isolation with equipment. The

Resman chemicals are encapsulated in resistant polymers and provide long-term monitoring of

where hydrocarbons and water are produced. Plastic strips are placed between the ribs of the

screens.


Question: is it an intrusive probe? How are the samples retrieved?


22/26

22

Answer: Human intervention, 2 people catching the samples. 120-200 samples over 2-3 days. Sample

takes 2 weeks to analyse in Trondheim.

Question: how long will the tracer last?

Answer: 5 years for oil, 1 year for water, increasing with increasing tracer concentration in polymer

and detection gets better (comparable to detecting a sugar cube dissolved in Olympic swimmingpool). Need 50 ml for tracer analysis but take 300 ml for repeat.

Question: any validation testing of ICD inflow simulation with tracer?

Answer: yes, part of log analysis and ICD performance confirmed with tracer analysis.

Question: what do the amplitudes mean?

Answer: relative flow between zones, taking into account the lengths of the zones.

Question: case where water breakthrough in zone 2, but tracer dissolves in water that could have

come from another zone, how does one eliminate cross flow possibility?

Answer: ICD not likely to allow cross flow, but it is a challenge to definitely identify zone. Cross flow

would also have given an oil tracer signal, mixing oil and water. Acid is not an issue, the polymers can

handle acid. Can plan for any chemical planned for the well, to test up front the polymers.

Round table discussion: life cycle drivers

Short term issues

Recommended start up / shut in procedure?

Operator: depends on sand control in place and placement success. Dictates startup sequence and

relation to other wells. If everything is as planned, green light to production, pull hard and quickly to

avoid hydrates, advantage of highly efficient sand control completion. Multiple zones with different

pressures do not impact recommendation, if all lab tests are OK.

Question: Is there a point at which a well is abandoned, sidetracked, if GP efficiency is low?

Answer: initial step is minimum rate to avoid hydrate formation, if the completion is a SAS or a GP

not with 100% placement, controlled choke changes to stabilized rate and bean up can take one

week.

Answer: let it rip also in SAS completion! (as fast as possible).

Answer: gentle startup can avoid problems while sudden startup can fail the screen.

Discussion: have only 5% SAS failure and do not bother with gentle beanup.

Question/Discussion: how can one have failure after 5 years? In High Rate Deep Water wells, must

have SC from day 1, due to depletion or changing production strategy down the line and

misunderstood reservoirs. Some operators can identify plugged screens from the onset and set a

plug above the section to minimize future failures.


23/26

23

Answer: many complications such as increasing water cut can occur, have guidelines for the different

completions, establish criteria for what needs to be avoided, erosion, for example.

Question/Discussion: what does it take to fail a deep water completion? There are some limits on

how one can break a cased hole completion. Procedure is that initial start is very cautious, getting

bottoms up first, then looking at pressure transient analysis to identify problems. Shut-in: no controlmost of the time due to emergency event. Drawdown strategy: when does one stop opening the

choke?

Does one treat injectors and producers similarly?some like to produce first then inject. Flow back

first is difficult for topside.

Filter cake removal. Does one get rid of everything? Pinhole, liftoff? HPHT, leaving in place too long,

might cook the FC, might be very hard to clean up.

Answer: with gravel packs, filter cake scraped up naturally, but removal critical in injectors.

Answer: always cleanup FC, depends on pressure regime.

Answer: get 10 % off good enough, but only if it is well distributed along the hole, no hotspots.

Answer: do usually the opposite, agrees it depends on pressure available in formation; rarely clean

up filter cake but keeps acid available if the filter cake is seen not to be removed, then go for acid

treatment.

Temporary abandonment:does the well come back on as it did during well testing? What about

corrosion?

Answer: can plan for temporary abandonment, but often gets much longer before set on production

again. Should maybe plan to use non damaging fluids from day 1.

Question: better to leave OBM or WBM in shut-in well?

Answer: would like to leave OBM, but if weighted, sag problem occurs.

Answer: tracers show if skin is changing upon beanup. Always interested in whether toe produces at

all; have seen a case where toe produced first in carbonate reservoir.

Answer: all wells are subsea, cleanup all wells and leave hydrocarbons, such that the wells can stayshut in for months.

Long term issues

Meet the plan10 or 20 yr wells?

Design for P&A should also be looked at. Should plan for all future issues, is the wellbore such that the whole life cycle can be handled

up to abandonment?


24/26

24

Difficult to figure out everything that can happen. What are the failure mechanisms? Manydifferent fashions, reason for the many available completions. Well should last long enough

to pay off.

Some producers have accumulated million of barrels, depletion is an issue. Oil producers are not in the break even business. Thinking in terms of maximizing profits. Use cumulative volume, not time as measure of life cycle. Sand Control defined for solids

larger that screen opening.

Many wells today doing much more than the plans were in the 90's. Operator does not repairsand control failure, but side tracks the completion.

Sand management is always planned for.Open Disscussion

Highest rate possible in frac pack?Frac Packs are used to avoid fines migration plugging. Frac Packed

wells have produced 130-150 mmcfd but with high velocity in the perforations. Is it possible to go up

to 200 mmcfd? What is the highest rate of perforation tunnel velocity without failing?

Oriented perforations may help the frac pack design. Reservoir heterogeneity is an issue; design is made on average perforation velocities. But

screens tend to fail at the maximum permeability areas. Frac packs mitigate high velocity

towards the screen.

1" perforation at 3 shots per foot (200 ft) generates a better rate than OH with 90% cleanupof FC. This gives a velocity of 10 ft/s.

Generally operators felt you could produce 200 mmcfd if properly designed, but no one hasseen a frac pack completion at these rates.

Which is better OHGP or SAS?:

Operatorsimplify methodology, go away from SAS as default, but still based on SAS and oriented

perforation.

Operatorcannot GP laterals, so these are ruled out.

OperatorGP is default, if simple enough go for SAS for cost effectiveness.

OperatorGP well with sand smaller that formation sand! Do a lot of SAS.

OperatorGP is the norm for higher productivity. Do both but prefer ESS with SAS as last choice.

Operatorwould like to go for more ESS.

OperatorGP.

Service Company - SAS can do more than people think.

OperatorExecution is 90% of the game and GP is more difficult to do than SAS.


25/26

25

OperatorSAS works fine and is cheaper to deploy.

Operatorin the lab, SAS never plug but they do plug in field.

Operatormost SC done with GP, but SAS much cheaper for horizontal complex wells. No literature

recipe on how to use SAS.

OperatorSAS get more successful as intervals get more compartmentalized.

Operatornon pay section have to be completed but not many test the geomechanics of

overburden shale.

Does one need centralizers?

Reduces friction, always good. Centralizers allow to keep crap on bottom of well. Acts as a snow plough: in soft formation can just push Filter Cake in front of centralizers. Onesolution never fits all. Centralizers helps to not allow damage to screens. Be aware of potential snow plough effect in soft formations. A lot of wear is seen on screens

so centralizers can help take the wear.

Place on top and bottom or middle of screen? Also in middle to avoid sagging of screen. Filter cake downhole is completely different than in lab tests, much more durable and

difficult to remove.

What is acceptable solids production? OHGP, frac pack, SAS?

Weight reduction exercise for platform, erosion modeling of downhole tubulars and whatcan be handled topside.

Need more understanding of proppant erosion to determine what screens can handle. Smaller companies can tailor facilities: 10 lbs per 1000 bbl is a threshold for having a cyclone

separator. Transient sand upon shut-in is a problem where one needs to choke down.

10 % per volume is too much. Some fields made 11000 tons of sand in the beginning. You can have fines coming through or transient sand on to a SAS, but if one produces sand

through the Sand Control , something is wrong!

Specs are 5 lbs per 1000 barrels. SAS and CHFP sized to allow between 14 to 20 microns. What about sand detection? Acoustic sensors, but only gives qualitative measurement. Facilities think that 0 lbs sand will

be produced, so one needs to get across to the facilities to prepare for some sand coming

anyway.

OHGP: how much sand coverage is good enough? 70% or is 100% needed?

The target is to stop the sand, the % does not mean much, unless it is as low as 30%, so 70%is good enough, based on caliper measurement with low certainty.

What is needed is gravel covering the screen whatever % that means. If screen is protected with a layer of sand this is good enough to mitigate the flow directly

into the screen. Screen can be seen as secondary insurance of SC.


26/26

Partially covered screen with flowback can push gravel aside and cause direct impingementon the screen. We strive for 100% coverage.

70% coverage is due to lack of centralizer. Nervous if not 100% coverage since it means that one section could be completely

uncovered. Service companies should be striving for 100%.

What happens to the gravel in the long term? Sagging, etc. the screens can act as vibrators asin cementing, so maybe less than 100% is dangerous on the long term.

Wrap up (Bala Gadiyar)Thanked the speakers (25 presentations). Many good discussions, networking opportunities. Next

ATW in 3 or 4 years.

76 attendees 37 companies represented 40 operators, 36 service company 15 countries represents

o 56% Europeo 36% North Americao 8% Rest of the World

Date post:	10-Feb-2018
Category:	Documents
Upload:	ali-aliiev
View:	214 times
Download:	0 times

2012 Spain Sand Control Scribe Report

Documents