SPE-191449-MS

Water Shut Offs in Two Openhole Gravel Pack Wells, Deepwater Angola

Paul Carragher, Sylvain Bedouet, and Didhiti Talapatra, BiSN; Andrea Hughes, John Curran, Wei Hou, Orlando
Kosi, Stan Ralph, Qiang Gao, Jesse Gracia, Jeanine Galvan, Patrick Calvert, Luis Alcoser, Doyle Dean, and David
Mason, BP

Copyright 2018, Society of Petroleum Engineers

This paper was prepared for presentation at the 2018 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, 24-26 September 2018.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents
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consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may
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Abstract
Achieving water shut-off in gravel packed wells is challenging, particularly being able to place a mechanical
barrier to flow into a gravel packed annulus. Gravel packed wells, often in deepwater environments, are
often high rate wells and interventions can be costly, therefore only techniques with a high probability of
success are typically sanctioned.
Many gravel pack wells are completed in multiple sands. If there are barriers between the sands that
are believed to be laterally extensive, and if water is entering the lower sand, then isolating the lower sand
can be a cost-effective intervention. Deepwater wells in Angola were reviewed as to whether a chemical
solution or a mechanical solution would be preferred.
Providing a suitable mechanical methodology could be developed, it was felt this would provide a
preferred solution. Further criteria for applying a mechanical solution were developed, to increase the
chances of success. Extensive well modelling was also conducted to identify an optimum set of plugs to
be placed in the well.
The operator identified a company that had an emerging technology that could offer such a solution.
They then worked together to mature the technology through a series of proof-of-concept tests, through
trials in Alaska, an early application in a deepwater well in the Gulf of Mexico, followed by a series of
qualification tests to be ready for application in Angola. The qualification tests considered not only the
mechanical configuration of the wells, but temperature, pressure and wellbore deviation. The application
would require placement using a tractor, therefore testing with connecting to the relevant equipment was
also incorporated in the plans for the wells.
Using a deepwater rig, several plugs were run in each well, including a meltable alloy plug. The latter
plug provided a barrier to flow in both the annulus and inside the sand screens. Although not providing a
barrier to shunt tubes, extensive modelling work at Cambridge university showed that it was possible to
influence gravel movement in the annulus and shunt tubes, so as to maximise the pressure loss.
Two wells have had plugging systems run. The first well has reduced water cut from 100% to ca. 40% and
shown a significant oil rate benefit. The second well has also shown a reduced water cut (from 70% to 40%).
2 SPE-191449-MS

Introduction
Zonal isolation in an openhole sand control application is difficult enough when planned for during the initial
completion design. An effective zone isolation post completion with a gravel packed annulus remains one
of the industry’s greatest challenges, complicated further by the costs involved in deepwater interventions.
The majority of deepwater openhole gravel packs fall into this latter group.
Incorporating zonal isolation into the initial completion design can take several forms. Non gravel packed
wells, advances in premium screen mesh coupled with a variety of openhole mechanical barriers in the
market place allow for effective zonal isolation for standalone screen applications.
Expandable screens and the newer screens technology that closes the openhole annular gap or conforms
with the openhole profile are also an option such an expandable metal sleeve annular barrier (ref. 1) or zonal
isolation barriers (ref. 2) can be used, but reliability is paramount in deep water. Increasing drawdowns and
collapse rating requirements limit their application in deep water.
Openhole gravel packed wells present a specific problem for openhole mechanical barriers. The openhole
mechanical barriers can be set prior to gravel packing, providing a flow path to the other compartments are
available to place the gravel pack. The gravel pack flow path between compartments will need to be shut-off
post gravel pack. There have been a number of these types of completions installed in Angola to date with
another operator. This completion technique still requires further intervention to address flow control inside
the screen such as plugs and/or straddles. However, it does remove the need to address the annulus flow path.
Setting mechanical barriers in the annulus post gravel pack is not really feasible as it requires voids in
the pack to allow the packers to expand to create the seal. The completion longevity will be compromised
by the presence of voids leading to hot spots during production. Swellable packers are an option (ref. 3),
but assuming a complete pack in the annulus, the space to swell is limited and as a consequence the zonal
isolation is ineffective.
Another option is shunt zonal isolation packer technology combined with internal shunt alternative path
technology (ref. 4).
The openhole gravel pack completion for the operator in Angola employs alternate path screens on both
a 5-inch and 5.5-inch base pipe screen in 8.5-inch and 9.5-inch openhole respectively. The screens have the
eccentric external alternate path configuration with two transport tubes and two packing tubes per joint. The
packing tubes are manifolded to the transport tubes at the top of each screen. The only entry or exit to the
alternate path is via the nozzles on the packing tubes. The screen filter media is direct wire-wrap ranging
from 9gauge on the 5-inch screen to 15gauge on the 5.5-inch screen. Any access to the annulus from the
inside of the screen would be via the perforated base pipe and through the direct wire wrap.
Through tubing plugs were consider on their own to be set inside the base pipe of the screen, but these
provide only limited choking benefit. Setting these plugs in the blank (unperforated) section of the screen
provide the greatest effect, but still limited due to the permeable flowpath in the annulus. A plugged annulus
in conjunction with the through tubing plugs provided the best mechanical barrier. The liquid metal plug
concept provided the best available choking effect to the water. The through tubing plugs and liquid metal
plug are in themselves mechanical barriers, but in this application, without access to plug the transport tube,
the system cannot be considered a pressure tight barrier. A flowpath, albeit tortous exists back through the
screen packing tube nozzle and into a gravel packed packing tube, then back into the transport tube likely
to be only partially packed. The water can flow up the transport tube avoiding both the base pipe plug and
annulus plug and exiting into the screen annulus above in the same fashion the gravel was placed.
There are a couple of important considerations to effectively place the liquid metal plug in the openhole
annulus. The liquid plug must have a base (prior installed base pipe plug) to sit on. Furthermore, the base
pipe plug needs to have a relatively blank profile on top to prevent excessive consumption of the liquid metal
flowing down inside the screen and not outside into the annulus. Well deviation is another consideration.
SPE-191449-MS 3

The molten liquid behaves similar to water and at very high deviations or horizontal will fall back on itself
limiting the effectiveness of the plug at the top of the openhole annulus.
This post completion zonal isolation technique was conducted on two candidate wells in Angola where
there was a requirement to shut off water being produced from the lowermost zone.

Angola Fields
Block 18 (B18) is located offshore Angola in water depths up to 1650m, approximately 120km west of the
Angola mainland. It comprises the existing Greater Plutonio (GtP) development and a potential tieback of
the Platina satellite.
Greater Plutonio comprises 5 fields; Plutonio, Cobalto, Galio, Paladio and Cromio and produced first oil
in October 2007. The development consists of a single centrally located FPSO (Floating Production Storage
and Offloading) vessel. Fluids are produced through subsea wells connected to an extensive seabed network
of flow lines and manifolds. Risers connect the seabed infrastructure to the FPSO which separates the fluids.
Gas and water are re-injected (or disposed of) and the oil is stored in the hull and periodically offloaded to
tankers. The depletion mechanism for all 5 fields is through water flood.
Block 31 (PSVM) is located offshore Angola in water depths up to 2050m, approximately 200 km off the
coast of Angola mainland (see Fig. 1). PSVM is comprised of 4 fields; Plutao, Saturno, Venus and Marte,
and produced first oil in December 2012. The development consists of a single centrally located FPSO
vessel. Fluids are produced through subsea wells connected to an extensive seabed network of flow lines
and manifolds. Risers connect the seabed infrastructure to the FPSO which separates the fluids. Gas and
water are re-injected (or disposed of) and the oil is stored in the FPSO hull and periodically offloaded to
tankers. The depletion mechanism for all 4 fields is through water flood with gas flood implemented in one
segment of Saturno.

Figure 1—Fields location, offshore Angola

Starting in August of 2013, GtP went onto natural decline, with a decline rate of approximately 16%.
The primary factors driving this decline are pressure depletion, and worsening system hydraulics resulting
from increased GORs and watercuts. Gas export will eventually result in decreased gas saturation in the
reservoir, reducing the negative impact of high GOR. The impact high watercut has on well productivity
and field decline is expected to worsen as the wells become more mature. As reservoir pressure declines and
watercuts increase, the well start-up risk increases, with the potential for significant deferrals. As a result,
4 SPE-191449-MS

the focus of the Well Intervention program has been water shut-offs, with these jobs expected to add value
and reduce field decline.
Well Cr-PB is a producer well in the Cromio field that was brought on line in 2008, producing from three
zones. The well became less competitive due to high water cut from the lower zone and was shut in.
Well PA-PD is a producer well in Plutao Alpha field was brought online in December of 2012, producing
from two zones. The well became less competitive due to high water cut from the lower zone.

Candidate Selection
A three stage process was used to identify suitable candidates for a water shut-off. In the first instance,
selection was based on whether the water cut was too high to prevent continuous production. Excessive
water rates penalised production from elsewhere in the subsea gathering system with the additional water
raising the hydrostatic head in the risers. Continuous efforts to optimise the field placed a preference on dry
production and many of the wet producers had been shut in for an extended period of time. This presented
a clear business case for lowering the water cut to support continued production without backing out the
flow of oil from elsewhere in the system.
With a set of suitable candidates, the screening process progressed to examine whether the saturation
profile of the surrounding rock made the well a suitable candidate for a water shut-off. The Angola wells
typically produce from multiple layers with the saturation of each layer driving the relative flow of oil
and water. The injection of water into multiple reservoir layers made it difficult to identify which layers
had watered out and which remained dry. Whilst a Production Logging Tool would normally provide the
required information, the subsea environment made this prohibitively expensive. Without a production log,
there was a significant risk of trapping oil behind or, even worse, targeting the wrong layer.
4-D seismic data provided a good insight into the migration of water between the injectors and producers
(see Figs 2 and 3). Unfortunately, the 4-D seismic was last shot in 2013 and the water saturation has
continued to evolve since. To supplement the insights from the 4-D seismic data, a near well bore reservoir
model was built to map the changes in well performance to the water saturation profiles within each layer.
By matching the model to multiple well tests it was possible to infer the movement of the water across
the different layers. Changes in water cut during the shut-in periods and the subsequent restarts provided
further insights into the origin of the water. Water would typically cross flow into the dry layers when the
well was off-line. Initial water cuts would be close to 100%, before returning to the steady state values
over a period of sustained production. The rate and extent to which the water cut dropped was analysed
in combination with the interdependency between water cut and drawdown to identify which layers were
dry and, in turn, which were wet.
SPE-191449-MS 5

Figure 2—Cr-PB: Water entry was identified to be in between O73 Upper and Lower
Sands, the recommendation was to set mechanical plugs to isolate the O73 Lower Zone.

Figure 3—PA-PD: Water entry was identified to be at the lower half of the
reservoir, the recommendation was to set mechanical plugs above PA60 Sand.

With the current saturation profile mapped within the reservoir model, the final task was to predict the
likely performance of the water shut-off. It was recognised that the concept of a water shut-off is a bit of a
misnomer, with little prospect of completely isolating the water. In particular, the transport tubes presented
a known flowpath for the water to flow to surface with the plugs imposing a resistance in the flow of
water rather than a solution for total isolation. The performance of past water shut-offs were analysed and
represented by an average pressure-flow response. The expected performance of each plug was coupled
with the reservoir model to simulate the likely performance of the water shut-off. Results from the integrated
6 SPE-191449-MS

model showed the importance of the shale layer in preventing the coning / fingering of water and the
screening leant in favour of those wells with a sizeable shale layer to set the plug against.
Finally, the expected performance was compared against the water cut of the remaining well stock to
ensure that the well could be produced continuously.

Chemical versus Mechanical Zonal Isolation

A screening study for application of relative permeability modifiers (RPMs) was carried out using an internal
decision tree spreadsheet based primarily on SPE 99371. Key parameters were (for a high angle well):

• Are there multiple sands in the well with significantly different water cuts (as best can be judged)?
⇒ If not, may be ineffective.
• Is the RPM being considered to remediate coning?
⇒ Not applicable.
• Are RPMs being considered to remediate a fracture connected to an aquifer?
⇒ Not applicable.
• Is the skin > 10?
⇒ Not applicable.
• Is the rock oil-wet?
⇒ Not applicable.
• Is the water cut from the well < 50%?
⇒ Considered as a guideline, but RPMs may be considered if natural flow stopped at low water
cuts.
• Is there a laterally extensive permeability barrier (shale?)?
⇒ Key factor.
All the wells in the production system were screened against these criteria and simulation model results
used. None of the wells in the production system scored 100% on all the criteria used. Also, it was noted
that candidates were only viable between water breakthrough in the first interval and water breakthrough in
the final interval. It was found that this provided a narrower interval than mechanical WSO, and therefore
a mechanical solution became the preferred option.

BiSN Technology
BiSN technology uses relatively low melting point Bismuth-based metal alloys and a chemical heater to
create downhole metal-to-metal seals. The low melting-point alloy is carried on to the tool as a solid sleeve
surrounding a high energy density heater. The heater is activated by sending a short duration high voltage
electrical signal through the wireline. As the exothermic reaction moves along the heater, the alloy sleeve
melts and alloy is displaced by gravity to fill the gap to be sealed. The alloy freezes at the bottom and the
top of the seal first due to a high temperature gradient. At the bottom the temperature gradient is ensured
by a large thermal mass, at the top wellbore fluid in contact with the alloy provides the necessary cooling.
The centre of the seal freezes last, the expansion of the alloy upon solidification is trapped in the seal body,
which creates an internal state of compressive stresses. The constrained expanded alloy provides the sealing
capability.
The technology was developed initially around the Wel-lok Tubing Seal (Wel-lok TS) system as a bridge
plug for P&A, which provided a permanent metal to metal seal solution. The Wel-lok TS is a relatively
short tool, carrying enough alloy to seal a typical 0.25" gap between the tubing ID and the tool mandrel –
see Fig 4. The operating principle of the Wel-lok TS suggested the solution for the mechanical WSO. By
SPE-191449-MS 7

providing more alloy to the system and directing the flow of alloy towards the bottom of the tool, the WSO
would let the metal flow through the sandscreen and into the gravel pack to provide a complete obstruction
for water production. A few modifications were brought to the original Wel-lok TS tool to provide the
correct parameters for the WSO application. The heater length and alloy volume were increased; a sleeve
was installed on the outside of the tool to focus the flow of alloy at the bottom where the WSO plug is
formed. The rest of the plug functions are similar, with a thermal mass at the bottom to provide a stop for
the alloy inside the sandscreen base pipe. Once the alloy releases from the sleeve, it starts to flow through
the sandscreen and into the gravel pack. The heater thermal reaction follows and reaches the bottom of the
tools, providing heat to the alloy to allow it to flow out to the open hole internal diameter (ID).

Figure 4—BiSN meltable alloy plug technology

Even with a longer heater and more alloy, the WSO tool can be conveyed on wireline (other conveyance
possibilities include slickline, pipe or coil-tubing). In this application a wireline and tractor conveyance
method were chosen because of the well trajectory.

BiSN Track Record

Prior to deployment for this job, the technology had been field tested in Alaska and Gulf of Mexico. The
Alaska job successfully deployed Wel-lok Tubing Seal inside 4.5" tubing in two different set of condition
of temperature and well inclinations. Both wells had a downhole pressure of around 3,600 psig. Well #1
had a downhole temperature of 89 deg. C and inclination of 19 degrees. Well #2 had a temperature of 75
8 SPE-191449-MS

deg.C and inclination of 47 degrees. The test validated the proper deployment and setting of the plug on
Wireline, the seals were successfully tested to 2,500 psig.
In the Gulf of Mexico instance, a WSO tool was deployed to stop water production from the bottom zone.
The downhole pressure was 9,500 psig, temperature 98 deg.C and the well had an inclination of 15 degrees.
The tool was set inside a 5" sand screen, to let the alloy flow out in the proppant to 9-5/8" perforated casing.
Overall, the water production was reduced by 50%.
Since this WSO Angola job, more applications have been deployed in the field, including multiple annular
seals and tubing seals in Norway and the UK.

Design of the Water Shut-offs

BP’s past experience of executing water shut-offs in Open Hole Gravel pack highlights the challenges of
reducing the flow of water, with the reservoir, annulus and transport tubes all providing a potential flowpath
for water to move to surface. To help design the water shut-off, the performance of 21 bridge plugs set
in BP over the past five years was evaluated. Well test data taken before and after each plug was set was
used to calculate the flowrate and pressure drop across each plug. Trending the pressure-flow performance
of one plug alongside another allowed a direct comparison to be made between the different water shut-
offs. As expected, there was a significant variation in performance, with the pressure drop across a single
plug ranging from as little as 30 psi (generating a minimal reduction in the flow of water) up to 550 psi
(delivering a near total reduction in water). The data painted a fascinating picture into the performance of
the water shut-offs with the following conclusions clearly visible from the data:

• Setting the plugs against a shale layer led to a significant improvement in performance

• Setting multiple plugs in succession produced a much higher pressure drop per plug than a single
plug set in isolation.
• The performance of a number of plugs fell below the theoretical pressure drop for Darcy flow,
indicating an absence of gravel or the potential for fluidisation.
A series of modelling studies were undertaken to explain the wide variation in performance. Work focused
on the three main pathways for the flow of water:

• Reservoir

• Gravel filled Annulus

• Transport Tubes

Modelling the near well bore region of the reservoir in Reveal, a reservoir simulator supplied by
Petroleum Experts, highlighted the difficulties of shutting off water in an open sand layer. Attempts to
plug the completion led to significant coning around the plug with a minimal reduction in the total rate.
Worryingly, the upward coning of water impeded the relative permeability of the hydrocarbon phase in the
section of the reservoir above the plug, leading to a reduction in productivity. In light of the results from
the Reveal simulations, all plugs were set adjacent to a shale layer.
With the annulus targeted through the Bismuth Alloy, the hydraulic modelling focused on the movement
of water through the transport tubes. Simulations showed that the pressure drop across the transport tubes
was highly dependent on the extent of gravel packing. With little to no gravel packing, a liquid rate of 2000
bbl/d produced a pressure drop as low as 1.8 psi/ft. On the other hand, the pressure drop increased to 365
psi/ft if the transport tube was packed with gravel. It quickly became clear that the success of the Angola
water shut-offs would be driven by the extent of gravel packing within the transport tubes.
SPE-191449-MS 9

Work conducted at the BP Institute in Cambridge demonstrated that the shear stress of the fluid moving
up the completion was sufficient to trigger the collapse of the gravel shell around a number of the nozzles.
Within the transport tubes, the gravel quickly fluidised and was transported upwards with the flow of water.
Downstream of the plug, the flow of water returned back to the base pipe as the overall resistance to flow
was less than in the transport tubes. With the gravel unable to pass through the screen, gravel began to
accumulate in the transport tubes. Over time, a gravel bridge slowly built downwards as further gravel
accumulated on the underside. The capillary force of the water moving through the gravel was sufficient
for the gravel bridge to withstand a significant pressure drop across it.
The water shut-offs were designed to maximise the probability of bridging gravel in the transport tubes
running parallel to the BiSN plug. A total of 2 Interwell plugs were set upstream of the BISN to promote
the flow of fluid and gravel into the transport tubes. A spacing of 20 to 50m was maintained between the
plugs to ensure that the volume of gravel available for fluidisation exceeded the volume of the transport
tubes downstream of the BiSN. Doing so increased the probability of bridging gravel around the BiSN plug.
Finally, the assembly of plugs was positioned in the shale layer located above the water producing layers
identified through the modelling work in the candidate selection process described earlier (see Fig. 5).

Figure 5—Schematic of plug installations, showing meltable plug

(in red) and additional plug(s) in screen (only one shown in figure).

Gravel bridging was targeted not only in design but also in operation. Following the well work, the
drawdown was gradually increased over a period of several weeks. With low initial rates, it was expected
that the water would return into the base pipe just downstream of the BiSN plug. With the gravel bridging
at the point where water returned to the base pipe, the intention was to bridge gravel as close to the BiSN
plug as possible. Once a gravel bridge had formed, the drawdown was gradually increased to promote the
fluidisation and deposition of gravel, leading to the downward growth of the gravel bridge through the
transport tubes. Over time, this increased the size of the gravel bridge in the transport tubes, raising the
performance of the water shut-off.

Qualification Work
A Surface Integration Test (SIT) was performed with the BiSN running tool and the e-line and conveyance
tool provider. The SIT tested compatibility and telemetry of the intended e-line toolstring and the BiSN
10 SPE-191449-MS

running tool. This e-line toolstring included Tractors, CCL and Electronic disconnect along with the BiSN
running tool. All components were tested to prevent accidental setting of the BiSN plug and function after
the firing voltage for the BiSN running tool was provided through the toolstring.
The SIT also tested the ability of the tractors to convey the full weight of the BiSN plug along a horizontal
test track.
A complete test was performed at a well test facility, in a 100ft well, where the conditions of the
plug test were designed to replicate and validate the conditions of the first well to deploy the technology
(except for the deviation because the test well was vertical). The testing plan considered the following tests
performed with the complete package from E-line unit and tool string from cable head, logging tools, tractor,
disconnect, running tool and plug:
1. Heater test-verified that heater did not fail by having a stop burn or a burn through.
2. Plug test in the gravel pack, wait for alloy to cool down and set, then activate disconnect and pull out
of hole the rest of the tool string, replicating the deployment and the operation.
3. Perform a leak test to the plug.
During the testing the pressures and temperatures were monitored to provide an indication if the tool had
been activated. If so, the heater would have been fired up, melting the alloy in situ. This was considered
during the design of the test fixture to provide the ability to monitor pressures and temperatures along the
setting depth of the plug by placing thermocouples both on the outside of the screen and outside the casing.
A mock-up of a mechanical plug was set just below the depth of the BiSN plug, to replicate the scenario
in the real operation where the plan was to set a mechanical plug before running the BiSN plug. The well
test was successfully performed, and the result of the plug was confirmed, with a very good shape (see Fig.
6) and successfully passing the leak rate test.

Figure 6—Test of plug in Houston facility, showing plug retrieved from casing after test
SPE-191449-MS 11

Operational Execution
The BiSN plugs were inspected upon arrival to Angola (from Houston) and QA checks performed on the
plugs and running tools prior to being sent offshore.
Once on the rig, the plugs and running tools were once again checked to confirm QA parameters were
within specification.
A second SIT was performed on the rig with the BiSN running tool and the e-line conveyance tools that
would be used to deploy the plug. This included activation and re-engagement of the electronic release tool
used to disconnect from the BiSN plug once set.
A detailed lifting plan was discussed and agreed upon to properly lift and stab the ~20’ long BiSN plug
and e-line conveyance tools.
A final tool check was performed, including testing the electronic disconnect, on the rig floor prior to
stabbing the BiSN plug and e-line toolstring into the lubricator (see Fig. 7) and running into the well.

Figure 7—Picking up the BiSN plug into the lubricator to stab into the surface flow tree

HSE
With a total of over 40,000 manhours between the two wells, zero spills, injuries and accidents were realized.
This achievement can be contributed to thorough planning, hazard identification and operational excellence.
During the planning phase of the well interventions, a multidisciplinary team met to identify risks in all
phases of the operation. This team consisted of personnel from intervention engineering, well operations,
rig operations and engineering, process safety engineering and central engineering. The team’s objectives
were to:

• Identify potential hazards that could result in scenarios with potential:

∘ Safety and health impacts.
∘ Environmental impacts.
∘ Financial impacts.
∘ Non-financial impacts.
12 SPE-191449-MS

• Consider consequences of the hazards.

• Perform risk ranking to:

∘ Determine the hazard scenario consequences using the company’s risk matrix categories.
∘ Estimate the risk of hazard scenarios utilizing the company’s risk matrix.
∘ Generate recommendations for risk mitigation measures to further reduce estimated risks.
• Identify safeguards that are in place to provide hazard prevention or mitigation.

• Propose recommendations, as needed, to eliminate, prevent, control or mitigate hazards.

• Provide assistance to facility management in its efforts to manage risk.

The approach taken to reduce the risk was based on the principles of ISD and the hierarchy of risk. In
this approach "Eliminating" the hazard is regarded as the most effective approach, with the least effective
approach being the use of "PPE".
The primary risks identified with regards to the BiSN plug related to the handling of the large component.
It was identified that the BiSN plug and running tool should be made up vertically; as assembling the plug
and running tool horizontally on the deck imparted side loading and dynamic loading on the plug component.
Early identification of the issue allowed for the modification to the plug to allow for attachment of lifting
clamps without causing damage to the plug.

Production Results
The two water shut-offs executed on PA-PD and CR-PB added a total of 5.5 mbd of incremental oil
production. Prior to the water shut-offs, the water cut was prohibitively high on both wells. Producing such
a high volume of water into the subsea gathering system had a negative impact on the back pressure and
productivity from neighbouring wells. The impact of the water was so severe that attempts to produce either
well led to a net reduction in the total oil rate for the field. Consequently, both wells were shut in with little
prospect that either would be produced in the near term.
The water cut on both CR-PB and PA-PD has dropped significantly following the execution of the water
shut-off. Initial water rates of 7.5 mbd and 9.5 mbd on CR-PB and PA-PD have fallen to 3 mbd and 1.2
mbd respectively with comparable drawdowns. Similarly, the water cut has dropped from 73% to 46% on
CR-PB and from 69% to 35% on PA-PD. With such a dramatic reduction in water, it has been possible to
produce both wells continuously without the fear of backing out production from elsewhere in the system.
Current oil rates stand at 3.3 mbd for CR-PB and 2.2 mbd for PA-PD.
Performance data is given in Figures 8-11 for both before and after the water shut-off. Prior to the
execution of the shut-offs, both wells saw a steady increase in the water cut. Crossflow was particularly
significant during shut-in periods, with the water cut approaching 100% once the well was returned to
production. Such was the dominance of cross flow that both wells showed an initial water cut in excess of
80 % following the intervention. Over a period of days (for CR-PB) and months (for PA-PD), the water
saturation in the upper layers dropped. With the plug assembly holding back water from the lower layers,
the water cut steadily declined to a competitive level. Control of drawdown proved critical for achieving
the lowest possible water cut, with the drawdown having a direct impact on the fluidisation and bridging
of gravel within the transport tubes. The impact that the drawdown had on the performance of the water
shut-off was most pronounced for CR-PB, where the careful control of drawdown (November – December
2017) was seen to have a 10% impact on the water cut. This equated to a 600 – 800 bbl/d reduction in the
water rate, which was sufficient to support continuous production from CR-PB.
SPE-191449-MS 13

Figure 8—Water (left hand axis) and oil rates (right hand axis) for PA-PD since water
broke through in November 2013. The water shut-off was executed in December 2016.

Figure 9—Water cut for PA-PD since November 2013 when water broke through. The water cut prior
to the water shut-off ranged from 70% to 100% depending on the extent of cross flow when the well
was shut-in and the length of the flowing period. The water shut-off reduced the water cut to 36%.

Figure 10—Water (left hand axis) and oil rates (right hand axis) for CR-PB.
14 SPE-191449-MS

Figure 11—Water cut since April 2016. The water shut-off reduced the water cut from 73% to 36%.

Long Term Reliability

The WSO tools in Angola have been set for over a year as of the writing date of this document. The water
production has continued to reduce, and the WSO tools are still performing as originally designed.
Two seal applications (annular and tubing) have been deployed in the North Sea in Q1 2017 and are
being monitored for pressure. As of end of 2017, no change in pressure have been reported, indicating a
good function of the tools.

Conclusions
1. The meltable plug system provides a means of placing a mechanical impediment to flow in the annulus
and production bore of a gravel packed well.
2. The additional plugs below and above the meltable alloy plug have facilitated the movement of gravel
to maximise pressure drop in the shunt tubes, thus minimizing bypass of water through the shunt tubes.
3. Given over a year since installations, the plugs appear to be continuing to be an effective impediment
to flow and this suggests that they are – as expected – a good long-term solution.
4. In the Angola environment, it was possible to use seismic data as a proxy for a production log, avoiding
multiple mobilizations and additional operational costs.

Acknowledgements
We would like to thank BP and their Angola partners Sonangol Sinopec International Limited, for
permission to publish this paper.
Thanks also to Adrian Weiss, Paul Beaumont, Marvin Miller, Julia Gibson and John Wood in BP for
their support. Thanks to Professor Andy Woods of Cambridge university for his work. Thanks also to Atul
Bhosale, Kuenda Yangala and Wilson Kuvingua in BP Angola.
The authors would also like to thank the BiSN staff in Houston for their support, also the rig crew offshore
Angola for safe and excellent operations.

Abbreviations
CCL Casing collar locator
FPSO Floating, production, storage, offloading vessel
SPE-191449-MS 15

GOR Gas oil ratio

GP Gravel Pack
GtP Greater Plutonio
HSE Health, Safety and Environment
ID Internal Diameter
ISD Information Services Directorate
PLT Production Logging Tool
PPE Personal Protective Equipment
PSI Pounds per square inch
PSVM Plutao, Saturno, Venus and Marte (field names)
QA Quality Assurance
RPM Relative Permeability Modifier
SIT System Integration Test
TS Tubing Seal
WSO Water Shut Off

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