This case study covers stimulation of nine subsea wells throughout offshore Angola, utilizing a riserless light well intervention vessel for hydraulic well access only, plus a dedicated stimulation vessel for treatment injection. These wells were intervened successfully over two campaigns. This was the first subsea offshore application of a newly developed, low-temperature single-stage, sandstone acidizing fluid.
VANESSA CRUZ, TotalEnergies and SAMUEL E. BREMNER, SLB
Introduction
The stimulation of subsea wells in offshore environments presents unique challenges, due to extreme conditions and the complexity of production systems. This case study focuses on the intervention and stimulation of nine subsea wells in offshore Angola, conducted over two campaigns in 2023 and 2024.
The stimulation campaign took place in Blocks 17 and 32. These blocks are approximately 150 to 180 km (93 to 112 mi) from the Angolan cost and 200 to 260 km (124 to 162 mi) from Luanda, respectively. They lie in water depths ranging from 600 to 2,200 m (1,978 to 7,218 ft). The development of these fields has been conceived with several producer wells, accompanied by several water injectors with the main objective of pressure support.
These wells target Miocene and Oligocene reservoirs, in mostly sandstone formations that, depending on the region and depth, can range from 50-60 mD to 800 mD, with average effective porosities of 10% to 25%. However, some fields, namely Zinia, have recorded permeabilities up to 5 Darcies with an average of 3 Darcies. Also depending on the depth of the productive zones, reservoir temperature ranges from 60°C to 135°C. All sands present some level of deconsolidation, and specifically the shallower reservoirs, which can be classified as unconsolidated sands.
Depending on the field and extension of the reservoirs, the wells have been conceived to target from a single reservoir to several intercalated reservoirs. In this regard, the typical well in each field is conceived as horizontal, contacting in some cases more than 1 km of productive sands, or vertical/slanted wells that traverse several productive layers (from 10 to 100 m of sands, or 98 to 358 ft) with diverse contrast of permeability and reservoir pressures, driven mainly by production, even if several injector wells have been drilled for pressure support as part of the fields development strategy.
In all cases, sand management is a challenge during different stages of the productive life of the wells. In this regard, wells have been conceived in OH with screened completions, using variations of conventional stand-alone screens and shunted screens in open-hole completions with gravel packs. Open-hole lengths ranged from 60 m to 1,500 m (197 ft to 4,921 ft). In general, most of the wells have not been conceived with packers with annular isolation to separate productive zones behind casing, increasing the challenge of fluid placement. Nevertheless, a few intelligent completions have been installed for some wells, but in all cases with a maximum of two selective zones.
Especially in the context of Block 17 and Block 32 wells, which contain sands with clays, sandstone acidizing can enhance well productivity, but it is essential to carefully manage the risks of precipitation. The presence of clays can exacerbate these precipitation issues, as clays can react with the acid and form additional precipitates. Additionally, the challenge of water production must be considered, as some wells in Blocks 17 and 32 have a high water cut percentage. High water production can lead to several issues, including reduced hydrocarbon production, corrosion and scaling in the wellbore and surface equipment, which are environmental concerns.
All the intervened wells in this campaign have been producing or injecting for at least six months and, in some cases, for more than 15 years after production on set. These wells are connected to different FPSOs, utilizing different risers and subsea lines, depending on their geographical location and project conception. As part of the intervention project, to promote the operator’s zero flaring policy, and given the capabilities of the LWIV, treatment flowbacks from the producer wells have been planned to be directly executed to the respective FPSOs through production pipelines and risers. Control of flowback corrosivity is, therefore, critical.
CANDIDATE SELECTION
The wells in Blocks 17 and 32 face similar issues, due primarily to damage caused by drilling, completions, fines migration, and clay swelling. The main objective of sandstone acidizing in these blocks is to dissolve near-wellbore damage. However, the presence of minerals, such as clays, feldspar, zeolites, and alumino-silicates complicates the acidizing process, as they can form undesirable precipitates when reacting with mud acid. To mitigate this, chelating agents can be used to prevent the formation of these precipitates.
The main damage mechanisms across these wells include residual mud cake damage, carbonate particles plugging the sand face and screens, organic and/or mixed deposits, fines migration (quartz and clays), and NSP contamination with shales and fines. The stimulation campaign, planned for early 2023 to early 2024, used a light intervention vessel package, with bullheading as the only treatment option. The challenges included refining fluid formulations, based on local lab testing; optimizing pumping sequences; testing diverters' compatibility and degradation time; and ensuring proper well clean-up to minimize carbon footprint.
Common points among the wells are the need for aggressive diversion strategies and the use of specific treatment fluids. The study emphasizes the importance of tailored treatments to address unique well characteristics and operational constraints. Additionally, the challenge of water cut, or excessive water production, is a significant issue in the stimulation of most of these wells, as it complicates the optimization of well productivity and necessitates careful consideration during treatment planning. The percentage of water cut has been increasing, which poses a challenge for maintaining efficient production and requires strategic management to mitigate its impact.
Multidisciplinary teams evaluate the candidate wells for the stimulation campaign. Several aspects were considered to establish the final list of candidates. To establish a first screening, the actual production of the wells versus their expected potential is considered, based on reservoir characteristics (permeability, pressure, connected length, etc.) and operating conditions. For new wells, this was basically the main determination: expectations from reservoir characteristics and modeled production versus actual production, plus well testing PBU interpretation and the construction history of the wells, have been used to determine the level of damage and the reason.
For all producing wells, the historical production was also considered, observing the variation of hydrocarbon and water production. The mineralogy of the reservoir was analyzed to understand the possibility of migratory clays. The completion and drilling history was reviewed, paying special attention to mud quality and events of mud losses. The wells' characteristics and the damage considered to be treated are summarized in Table 1.
STIMULATION FLUIDS
Stimulation fluids were selected, based on the candidate selection result and the damage identification process. Here, the damage mechanism consisted of a combination of fines migration, organic deposits, loss control material and drilling mud cake damage. This included candidates with multiple damage types, resulting in multi-purpose stimulation fluids being selected. The main stimulation fluids used during the stimulation campaign are in the following list.
Organic Acid Solvent Blend (OAS). OAS is a multifunctional solvent fluid, used to remove multiple formation damages like water block, organic deposits, viscous oil in place, emulsion and wettability changes. For the scope of this project, OAS was identified as a good fluid to remove the damage caused by original oil-based mud (OBM) used to drill the well. The use of OBM created wettability changes, remaining emulsions damage and filter cake damage. Because there might be more than one kind of damage, OAS was selected as the best fluid to remove this multiple damage in one shot, providing good value to the logistics and execution of the operation.
Single-Stage Sandstone Acidizing Fluids (SSAF). To avoid using the basic stepwise approach typically taken when acidizing sandstone formations, and dimmish the risk of creating insoluble precipitates, the single-stage sandstone acidizing fluids were considered for this stimulation campaign. SSAF combines in a true, single-step treatment the functions of solvent pre-flush, aqueous pre-flush, acid pre-flush, and main acid. These fluids are an excellent alternative to eliminate the risk of precipitation, reduce the number of steps and volume, easing the operations and logistics of the stimulation job.
There are several versions of SSAF. The first ones were developed back in 2010 (Armirola et al. 2011; Husen et al. 2002; Mahmoud et al.2011; Reyes et al. 2013; Urraca and Ferenc 2009) and were mostly chelant-based chemical, to make them compatible with carbonate in the formation. This version of fluids was pumped in two wells of this campaign, in which the temperature was above 200oF, and the chelant had good reactivity with some components of the rock or damaging material.
A novel SSAF was developed in 2022 (Haiya Zhao et al. 2022). This fluid was designed to overcome the most common challenges addressed during sandstone acidizing, which includes the need for multiple fluid types, good design and execution to prevent formation damage, and multi-stage operations that require large volumes and long pumping times. The novel SSAF expanded the temperature range of application down to 65oF, which makes it a good alternative when stimulating shallow reservoirs in deepwater environments. This novel SSAF was used during the stimulation of one of the wells of this campaign.
SSAF is compatible with high carbonate content rocks; therefore, it does not need acid pre-flush prior to the main acid treatment. It can dissolve silts, clays and carbonate, and increases permeability. It can also significantly remove the damage caused by clay swelling and fines migration. Fines migration was identified as one of the main damage mechanisms in several of the wells treated during the campaign
Emulsified acid is an acid-outside phase emulsion prepared and stabilized with a surfactant. The purpose of the dispersion is to simultaneously dissolve acid-soluble materials and remove organic component, paraffinic or asphaltic deposits. The most common acid used is 15% HCl, but different concentrations of HCl or different acid types could be used, depending on the application. Hydrocarbon solvents are typically used as the internal emulsion phase. The hydrocarbon solvents choice depends on the type of organic deposits and their dispersibility in the solvent. Emulsified acid accomplishes the removal of both oily deposits and acid-soluble minerals continuously in one stage, this eliminates the need for multi-stage treatments.
For the wells stimulated during this campaign, emulsified acid was used to remove the damage caused by oil-based mud (OBM) and loss control material (LCM). OBMs are known to create damage in the formation, due to their content of strong oil wetting agents and their trend to create stable emulsion when mixing with high-salinity formation brines. Additionally, HCl-soluble LCM had been added during the drilling and completion of these wells to prevent drilling mud losses.
Severe damage caused by the OBM, mudcake and LCM had been identified as one of the main damage mechanisms in several of the wells. Emulsified acid was found to effectively remove in a single treatment the damage created by the oil base mud. The solvent reverted the damage caused by the strong oil wet surfactants, and the HCl removed the damage created by the mudcake and LCM.
Degradable Particulate Diverter. Most of the wells in this campaign were completed in highly deviated, long reservoir sections of open-hole completions with screened completions—either stand-alone screens (SAS) or shunted screens. The open-hole sections were 400 to 500 m (1,312 to 1,640 ft) long, with shale intercalations and significant permeability contracts between layers. This made it critical to consider the use of near-wellbore diverters to maximize the stimulation of the entire open-hole section. The presence of screens limited the size of the particulate diverter; the particulate should be able to pass through the limited entry in the screen and provide diversion at the formation face. The particulate diverter was carried by a viscoelastic surfactant fluid, which also contributed to the diversion process by the increase of the fluid viscosity in the near-wellbore area.
Degradable particulate diverter in a viscoelastic surfactant fluid was used to provide diversion by creating a temporal degradable filter cake at the formation face, assisted by higher viscosity of the carrier fluid in the porous media. Degradable particulate diverters have been used in stimulation operations for many years as a proven technology to optimize the efficiency of the treatments (Van Domelen 2017) (Vidma, et al. 2021) (Khan, et al. 2021). The degradable particulate diverter was considered for this campaign, because its characteristics include being fully degradable, non-damaging to the formation, suitable for limited entry completions and appropriate for the wells’ bottomhole temperature.
Lab testing. Laboratory testing was conducted to complement the formation damage characterization carried out during the candidate recognition phase. The stimulation fluid selection was further refined with extensive laboratory testing that included core flow, X-ray diffraction (XRD), dissolution testing, inductively coupled plasma analysis (ICP), and fluid compatibility tests to select the optimum treating fluid for each well. Compatibility testing with the stimulation fluids and the reservoir fluids was carried out successfully and demonstrated a good fluid break. The focus of these tests was to ensure that the FPSO was able to handle flow fluids in terms of emulsions and spent acid.
CORE FLOW TEST
Three core plugs were used to evaluate the efficiency of the SSAF proposed to stimulate three wells of this campaign. The objective of the SSAF system was to remove the damage caused by silts, clays and fines migration. XRD data from an offset well showed that the amounts of clays, micas and feldspars could total more than 20% (Table 2) of the formation mineralogy, which could contribute to one of the formation damages. The clays present in the formation are illite and Kaolinite, which are considered migratory clays.
The SSAF performance was evaluated and compared against the performance of conventional sandstone acidizing fluids. The fluids designed to treat these wells were injected into the core, following the same sequence. Prior to the injection of the stimulation fluid, a base line permeability was measured and compared against the final core permeability to calculate the percentage of regained permeability. This is an indication of how effective the fluid can stimulate the formation by removing the damage caused by the presence of silts, clays and fines. Figure 1 shows some of the core flow test data with SSAF.
The core flow tests showed a notable increase (120%) in permeability after being treated with SSAF, Table 3. Effluent samples were taken for ICP analysis. The ICP analysis showed the presence of Si, Ca and Al ions, which indicated that the SSAF effectively reacted with aluminosilicates and some minerals containing calcium.
DISSOLUTION TESTS
One of the candidate wells had drilling cutting samples. Four samples from different formation depths were selected for XRD measurements to quantify the mineral content for the cuttings. The XRD results are included in Table 4. The high presence of calcium carbonate material was expected and came from the use of LCM during drilling the reservoir section.
Dissolution tests were performed to four interval samples from the same formation that would be stimulated. The dissolution tests were performed with Regular Mud Acid (RMA) and its respective 15% HCl pre-flush and the SSAF without pre-flush at 160oF (71oC). Both stimulation fluid systems presented very high dissolution capacity, all of them above 50%, Table 5. It was considered that despite the lower values of SSAF dissolution compared to HCl-RMA mixture, the SSAF would provide a more controlled reaction rate with no risk of deconsolidating the rock matrix. At the same time, it would eliminate the need for HCl pre-flush, which brings operational, logistical and economic benefits.
INDUCTIVELY COUPLED PLASMA ANALYSIS (ICP)
ICP analysis is a technique in which the composition of elements in samples can be determined, using plasma and spectrometer. The ICP analysis was performed to effluent samples taken during the core flow tests and the drilling cutting dissolution test. The ICP analysis helped to understand the reaction of the stimulation fluids with the different minerals found in the formation, the composition of the sub-products of the reaction, and the potential of the creation of any insoluble precipitates, which is very common in sandstone acidizing treatments.
The effluent samples for each of the fluids pumped during the core flow were collected during the test, and cation concentrations were analyzed, using the ICP apparatus. The cations determined via ICP were aluminum (Al), calcium (Ca), iron (Fe), potassium (K), magnesium (Mg), sodium (Na), and silica (Si). Ion quantification suggested silica and aluminum as the main ions in the effluent, which was expected as products of the dissolution of aluminosilicates by the acids pumped into the cores
Figure 2 is an example of one of the ICP analyses performed on the effluent samples taken during the core flow tests. The ion concentrations are plotted as a function of fluid volume pumped over the test duration. There is a volume of transition between each of the fluid stages, which reflects on the first sample of each stage and could still be related to the previous stage.
STIMULATION STRATEGY
Each of the candidates was stimulated, using the vessel-to-vessel intervention method, as described in Alistair Roy et al 2021. This is where the lightweight intervention vessel (LWIV) provides connection to the subsea tree via the well control package. A stimulation vessel then connects to the LWIV via a high- pressure coflexip hose. This method allows the LWIV to focus on well access and the stimulation vessel to focus on stimulation fluids and delivery, as depicted in Fig. 3.
In these operations, the stimulation vessel was the GreatSHIP Ramya. With hydraulic connection to the subsea tree, via two coiled tubing downlines, the stimulation strategy relied on a bullheading operation to deliver stimulation fluids to the formation. With stand-alone screen formations and lengths described in Table 1, diversion techniques were introduced to improve the chances of complete wellbore coverage. Here, the diversion strategy relied on viscoelastic surfactants to provide downhole viscosity and breaking mechanism when the diverter encountered formation oils, plus degradable particles to provide additional pressure drop as the fluid travelled through the screens. To account for multiple sources of potential damage that was introduced during the candidate selection section, the strategy for each candidate consisted of emulsified acid, combined with SSAF and a diversion step in a single cycle. This cycle was then repeated, based on the open-hole length, as depicted in Fig. 4.
The purpose of the emulsified acid step was to ensure that any remaining filter cake from the drilling phase was effectively removed. This, then, allows the SSAF fluid to penetrate deep into the formation without spending excessive quantities at the filter cake. Post-acid steps saw the deployment of a two- phased over-flush. The first over-flush was to ensure that the critical matrix was clear of stimulation products, reducing the potential for any particulates dropping in this region.
The second over-flush was carried out 8 to 12 hrs later. This was included in the program to provide a mitigation measure against any unspent acid returning to the FPSO on flowback, plus provide additional corrosion protection as secondary over-flush contained additional corrosion inhibitor. This practice was applied to all stimulation operations for the key purpose of protecting the flowline and making FPSO flowback more manageable.
Determination of the required acid volume was achieved through a combination of volumetric calculations, based on contact length, formation porosity and target penetration. The target penetration depth was linked to damage mechanism. Here, the wells that recorded drilling mud-induced wellbore damage only required a short formation penetration, such as 2 ft. This enabled engineers to make practical designs that matched operational needs for the long net screen length targets, found in wells 1 and 3, Table 1.
For candidates where the damage mechanism was more formation-focused, target penetration was increased to 3.5 ft. This created acid-per-ft values from 15 gal/ft to 68 gal/ft. The wide range in design volumes highlights that a simple volumetric method is unsuitable for determining acid volume in sandstone formations with varying damage types and net pay lengths. Instead, the volumetric method was used as a starting point for digital simulation of the treatment design.
Calibration of the stimulation strategy was carried out, using a reservoir-scale digital platform. The escalating complexity method ( V. Mutschler et al 2024) was deployed to model each of the candidate wells. The objective of this process was to estimate fluid penetration and optimize wellbore coverage with the adjustment of diversion volumes and rates. An example pumping design is presented in Table 6.
This schedule created the following simulation, where the focus was on zone coverage and skin reduction across the wellbore. The result of the simulation is shown in Fig. 5. The other candidates followed a similar approach; however, due to a higher BH temperature, the chelatant version of SSFA was deployed. The strategy was similar, with an initial lead of water control fluid followed by cycles of emulsified acid to treat the filter cake damage and SSFA for deep formation penetration.
EXECUTION
The execution of the campaign was carried out, with the LWIV vessel running the well intervention package and taking ownership of the well from the local FPSO. On successful handover, the stimulation vessel was called in and connected to the LWIV by a high-pressure coflexip hose via a suitable hose hanger installed on the LWIV. Pump rate started at 3.8 bbl/min. and increased to a maximum pump rate of 8.0 bbl/min., as shown in Fig. 6. In these deployments, the surface pressure is dictated by the two coiled tubing down lines that provide connection to the subsea tree. Here, surface pressure peaks at 7,500 psi, compared to subsea tree pressure of 2,610 psi.
The coiled tubing connection method accounts for approximately 5000 psi at maximum rate or 66% of the total surface pressure, shown in Fig. 7. This is why we see a clear drop in surface pressure during the pumping of the viscose diverter. At these pump rates, the viscosity of the fluid enables laminar flow which helps reduce pipe friction. This pressure effect is present on all LWIV hydraulic interventions during the campaign and is a useful reminder that maximum pump rate is always going to be limited by the downline method to the subsea tree and the size of the well intervention package. This is why maximum rate is restricted to 8.5 bbl/min.
Well 9 had a recorded BHST of 74oC. Prior to pumping the main operation, the BH temperature gauge recorded 70oC. On completion of the main pumping sequence, the temperature gauge recorded a BH temperature of 18oC. In this case, the gauge is located at 2,822 m (7,487 ft), MD, compared to a top screen depth of 3,180 m (10,433 ft), MD. This difference highlights that the recorded BH temperature is heavily influenced by the treatment fluid temperature and should not be considered as the actual BH formation temperature. Initial investigation of BH gauge data during fluid placement does not provide an effective means of determining success.
Surface pressure is influenced too much by the downline deployment method, and BHP does not show enough contrast. Given that distance from gauge to top of screens is 298 m and 949 m to the bottom, these distances must be taken into consideration. In this, the mid-point of the screens has been selected as the reference point allowing for the addition of hydrostatic pressure and pipe friction. In this case, subsea wellhead pressure and BH gauge pressure can be used as the reference point for calculating fluid friction. From here, all that is required is the extension of expected friction pressure to the reference point. This allows for estimation of the diversion and acid response at the formation.
This adjustment does allow for a better interpretation of the BH response, but given the open-hole nature of the well and the stand-alone screen completion, even this interpretation is an estimation at best. The key observation from Fig. 8 is that the viscoelastic diverting agent is able to produce a diversion response in the 10-psi range. The emulsified acid produces a small uplift in BH pressure in the range of 30 psi, this is likely due to the own viscosity of the emulsified acid and the friction that it creates when passing through the SAS and entering the formation. SSAF has a neutral response, with no recordable pressure gain or loss during injection.
Well 5 was the second of the three candidates treated with SSAF; however, this fluid was formulated for a higher bottomhole temperature and contained a high proportion of chelating agents as the primary method for stimulation. BH temperature was recorded at 95oC prior to the treatment and dropped to 55oC during placement, Fig. 9. Pump rate peaked at 6 bbl/min., with a drop to 1 bbl/min. during the final flush. This candidate saw the deployment of a viscoelastic diverting agent with degradable nano particles, with a concentration of 150 Ibs/1,000 gal added. This addition enabled better diversion response, as the diverting material was able to pass through the screens and form a filter cake on the formation face. The challenge that was encountered during this operation was in the final displacement. The objective of the displacement was to leave the SSAF fluid in the near-wellbore area, with the well left in diesel. This would have enabled the clay stabilization properties of the SSAF to treat the near-wellbore region, plus leave the well with a low hydrostatic fluid for easy flowback.
This scenario created a perfect alignment of poor injectivity at the end of the treatment. Diversion material had been deployed to improve zone coverage, and high-temperature SSAF fluid was placed near the wellbore during a time when the formation had received cool-down, which inhibits reaction rate and slows down formation penetration, combined with a low hydrostatic fluid to displace the well. The result was an increase in BH pressure and a reduction in hydrostatic pressure that pushed surface and wellhead pressure to the pumping limit.
Accordingly, 90% of the treatment was pumped within 7 hrs; however, the final displacement step took 6 hrs to complete. In this instance, the treatment was displaced successfully as planned; however, the contingency needs to be available, in case it’s not possible to continue to inject into the formation. This contingency led to the following mitigation measures being applied during the planning phases: Corrosion testing time should be for as long as practical, up to 48 hrs. This gives engineering teams confidence that enough time is available to allow the diverter to degrade or formation pressure to fall off and resume pumping.
FLOWBACK
The flowback of all the candidate wells is via the subsea production line and to the supporting FPSO. This flowback method is dependent on the fluid being spent, with little to no emulsions in the returns, as the FPSO’s ability to handle complex returns is limited. To account for this pre-job testing involved a wide range of emulsion compatibility tests, using stimulation and formation fluids to predict fluid behavior on return. Although fluid tests showed no cause for concern, an additional brine overflush step was included in the program. As well, dealing with corrosion concerns with spent fluids, this step allowed for additional dilution of the flowback fluids. This strategy helped to mitigate fluid return challenges to the FPSO.
WELL EVALUATION
Post intervention evaluation of the candidate wells has been broken down into a number of topics—this covers execution objectives, fluid placement and well results. Execution evaluation is the simplest form of evaluation, as the delivery of stimulation fluids is simple to track. With operational safety and well integrity being the most important objectives, these recorded good results, with no incidents of either category throughout the various campaigns.
Regarding operational efficiency, this did not meet the objective, as some technical challenges were experienced during the intervention campaign. One particular situation worth noting for future operations is the use of solvents in the pumping fluids. In all the wells, large quantities of Xylene were pumped as a 10% solution in the emulsified acid fluid. This solvent can result in increased degradation of sealing parts found within surface valves. Although not apparent at the start of the campaign, by the time of the last two treatments, due to the executed surface equipment, operators reported a significant drop in valve performance. This resulted in nearly all high-pressure plug and check valves needing to be replaced or re-packed. For future treatments, planning will focus on this aspect, to ensure that sufficient spares and replacements are available.
Fluid placement examines the fluid’s abilities to treat the entire interval. The candidate wells covered screen lengths from 66 to 971 m (216 to 3,186 ft). Simulation of pumping response has been completed and shows a reasonable level of zone coverage. However, for wells where screen length is in excess of 600 m (1,969 ft) placement is not assured. Based on production results, it is expected that approximately 20% of the toe sections of the well were not fully stimulated.
Given that all these wells need to be treated via bullheading, there is little that can be done to improve placement. In these two wells, diverter volume accounts for approximately one-third of the acid volume. For example, well 3 deployed 1,200 bbl of emulsified acid and 360 bbl of diverter. This ratio was acceptable for the smaller-length wells; however, this is not enough for the longer wells. As a result, any future well interventions with a screen length in excess of 600 m (1,969 ft) will see the diverter volume-to-acid ratio increased to one-half.
Well production results, from a global perspective looking at all wells, were successful. Overall, production and injection increased by 150% and 200%, respectively. However, on a well-by-well basis, the intervention success is not straightforward. Of the nine wells stimulated, two wells recorded no improvement in post-stimulation productivity index (PI), one injector well saw the re-activation of a previously blocked zone, and five wells recorded improvements in line with expected production targets.
However, one well showed production improvement that doubled the PI and resulted in a significant gain in output. This was recorded in well 6, where SSAF fluid was deployed. These results follow an expected trend with mature field interventions, where it is unrealistic to expect all well interventions to result in improvements. Hence, this broad approach of treating multiple wells in stimulation campaigns is the best chance to see overall field improvements.
CONCLUSION
Over the course of this project, two independent subsea campaigns were completed, with nine wells stimulated over 10 individual treatments. Each treatment successfully pumped the design amount of fluids without HSE event and were able to successfully flow back. The SSAF fluid system was a key contributor to the campaign’s success and allowed design engineers to stimulate long open-hole intervals with stand-alone screens. The usual practice in sandstone stimulation is to pump a series of fluids in sequence to protect the formation from unwanted secondary and tertiary precipitation. In long intervals, this type of strategy is difficult to implement, as it is not possible to prevent all the fluids from mixing in the lateral length. Diversion became a key strategy for its success. The use of viscoelastic surfactants and degradable particles helped support zone coverage during each stimulation, in addition to protecting water zones from excessive stimulation.
Challenges were faced during assessment of diversion potential, even with BH gauge data, as the lateral intervals are long. The use of particles was successful; however, this created some pumping challenges during treatment placement. A highlight during subsea intervention is the effect of low-density displacement fluids and diverters on the ability to achieve a good pumping route. This combination creates some risk to the pumping operation and must be considered during planning. WO
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VANESSA CRUZ at TotalEnergies has a background in chemistry and over 18 years of expertise in Formation Damage and Production Enhancement. She joined TotalEnergies in 2004 as a lab technician, taking leadership of the Headquarters Reservoir Wellbore Interface laboratory in 2018. Since joining the well stimulation specialists’ team in 2023, Ms. Cruz has been supporting operations globally with well diagnosis, stimulation design, and on-site supervision.
SAMUEL BREMNER is an SLB technical expert with 15 years of experience dedicated to production enhancement in environments ranging from vessel-based stimulation in the North Sea to deepwater and land operations in West Africa. His career at SLB has developed from a background in chemical engineering and environmental management to focus on intervention operations across multiple oilfield service disciplines.