Fines migration is the common formation damage mechanism in the sandstone reservoir of field B which has less established information on mineralogy distribution. There were many attempts to remediate the formation damage using conventional mud acid fluid system but resulted in mixed success rates. This situation warrant for the need for a modified acid recipe to avoid aggravation of fines migration problems in this field post acid treatment. This paper presents the pilot application of a modified HF acid recipe incorporating chelate. The paper also depict the evaluation process that includes candidate selection, laboratory workflow and results, treatment design, execution strategy and the post job analysis on well B-1S. In order to increase the acid stimulation success rate, the team analyzed numerous post job reports of the nearby wells that were previously treated with conventional mud acid system. The root causes of the previous job failures were identified, such as prolonged soaking of acid in the formation due to unplanned platform shutdown and limited platform deck space. Taking these factors into account, the modified HF acid system (with 1.0% HF) was selected for execution in B Field. The pilot execution resulted in double the production compared to the pre-treatment rate. The modified HF acid system has also improved the economics of the project due to its lower cost since it is a one-step system and has lower additives requirement.

In Q4 2017, the first extended-reach horizontal oil producer was completed in S-Field, with the horizontal section designed with nine isolation compartments with swellable packers. Each compartment was configured with an inflow control device (ICD) and an integral sleeve (on/off function) attached to the ICD’s joint. This paper discusses the effectiveness of the ICD technology in terms of sustaining incremental cumulative oil production by delaying water-breakthrough and subsequently reducing undesired water cut after water-breakthrough. An extensive post-job evaluation on production performance was conducted to evaluate the performance of the installed ICDs. The workflow was divided into three stages: history matching, forecasting, and post-job ICD evaluation. During history matching, the horizontal well with the ICDs was modeled using a high-resolution numerical simulator, and the reservoir model was calibrated with production data from a well test. Actual production rates and the water-breakthrough time were matched by revisiting key subsurface uncertainties from the sector model, such as aquifer strength, oil/water-contact, and relative permeability using the Corey correlation. The history-matched model was then used for the forecasting stage to predict cumulative production on a longer-term basis. Lastly, the performance of the ICDs was quantified after 4 years of production by comparing the oil increment from the ICD completion to the non-ICD case as baseline that would have been a miss of additional oil cumulative. Over the past 4 years, this horizontal well produced more than expected, with approximately 2–4 times more oil production than the estimated rate provided in the field development plan (FDP), whereby the lower completion is design optimally based on real-time ICD modeling updates. There were few uncertainties in the subsurface parameters such as fluid contact, fluid characterization, and the nature of an aquifer, were incorporated in the history-matching stage using sensitivity analysis and uncertainty range estimation. On the basis of actual and history-matched production performance, the well with the installed ICDs is projected to produce more than the non-ICD OH case with an improved cumulative oil production gain of as much as 6% and an 8% water reduction over 12 years of production. In addition, the ICD enables downhole influx balancing to delay the water breakthrough by 4 months compared to the OH case. The reduction or delay of water production is beneficial to the field to enhance oil recovery from the well. This case study demonstrates a successful ICD deployment under uncertainties, where during a real-time study in 2017, similar uncertainties were incorporated in high-resolution ICD modeling conditioned with real-time petrophysical data from logging while drilling (LWD) measurements. The use of ICD technology in this well demonstrated that zonal control efficiency could be achieved across the horizontal section and increased oil production over time. The ICDs were designed to deter early water breakthrough supported by well tests and manual fluid sampling indicating the water production only occur after 4 years of production and sand-free till to-date.

Gravel packing in a multilayer reservoir during an infill development project requires treating each zone individually, one after the other, based on reservoir characterization. This paper discusses the installation of an enhanced 7-in. multizone system to achieve both technical and operational efficiency, and the lessons learned that enabled placement of an optimized high-rate water pack (HRWP) in the two lower zones and an extension pack in the uppermost zone. This new approach helps make multizone cased-hole gravel-pack (CHGP) completions a more technically viable and cost-effective solution. Conventional CHGPs are limited to either stack-pack completions, which can incur high cost because of the considerable rig time required for multizone operations, or alternate-path single-trip multizone completions that treat all the target zones simultaneously, with one pumping operation. However, this method does not allow for individual treatment to suit reservoir characterization. The enhanced 7-in. multizone system can significantly reduce well completion costs and pinpoint the gravel placement technique for each zone, without pump-rate limitations caused by excessive friction in the long interval system, and without any fiuid-loss issues after installation because of the modular sliding side-door (SSD) screen design feature. A sump packer run on wireline acts as a bottom isolation packer and as a depth reference for subsequent tubing-conveyed perforating (TCP) and wellbore cleanup (WBCU) operations. All three zones were covered by 12-gauge wire-wrapped modular screens furnished with blank pipe, packer extension, and straddled by two multizone isolation packers between the zones, with a retrievable sealbore gravel-pack packer at the top. The entire assembly was run in a single trip, therefore rig time optimization was achieved. The two lower zones were treated with HRWPs, while the top zone was treated with an extension pack. During circulation testing on the lowermost zone, high pumping pressure was recorded, and after thorough observation of both pumping parameters and tool configuration, it was determined that the reduced inner diameter (ID) in the shifter might have been a causal factor, thereby restricting the flow area. This was later addressed with the implementation of a perforated pup joint placed above the MKP shifting tool. The well was completed within the planned budget and time and successfully put on sand-free production, exceeding the field development planning (FDP) target. The enhanced 7-in. multizone system enabled the project team to beat the previous worldwide track record, which was an HRWP treatment only. As a result of proper fluid selection and rigorous laboratory testing, linear gel was used to transport 3 ppa of slurry at 10 bbl/min, resulting in a world-first extension pack with a 317-lbm/ft packing factor.

A multizone cased hole completion with a bottom hole assembly of world-record length at 2,600 ft was installed in Malaysia in November 2019 where three zones were simultaneously gravel packed in a single trip utilizing shunt tube technology. This sand control completion was successfully executed with a combination of sand control pumping and sand control tools, unconventionally performed by two different service providers. The well consisted of three zones of interest approximately 1,000 ft apart. The bottomhole assembly was designed with two shunted cup packers for zonal isolation and shunted 12-gauge wire wrapped screens across each perforation. The shunts were left open ended below the cup packers, allowing the carrier fluid to exit the zone below with minimal friction. Downhole memory gauges were deployed along the washpipes for post job evaluation. Diligent lab testing was performed to select the carrier fluid, a clarified high-grade xanthan polymer with good 20/40 proppant suspension with less formation damage and acceptable dehydration to avoid bridging inside the shunts. Detailed risk assessment that was performed during the planning stage focusing on interfaces, equipment limitations, expediting, and decision flow charts between the two service providers led to flawless execution at the wellsite. Compared with conventional stack-pack completion, significant time savings of approximately seven days was observed with this single-trip design; the concept of open-ended shunts below the cup packers replaced the majority of the shunted blank pipes with standard blank pipes, eliminating the time required to install jumper tubes. Good results were observed during the injectivity test in addition to the well already having losses of 20 bbl/h. Hence, no acidizing was required prior to the gravel-packing operation. Based on surface monitoring, there was clear indication of sequential packing from the top zone to the bottom-most zone via shunt tubes, followed by a final screenout. Findings were further verified after performing the downhole bottomhole gauge analysis using the retrieved data from the memory gauges. The well has been in production since December 2019.

Gravel packing in a multilayer reservoir during an in?ll development project requires treating each zone individually, one after the other, based on reservoir characterization. This paper discusses the installation of an enhanced 7-in. multizone system to achieve both technical and operational efficiency, and the lessons learned that enabled placement of an optimized high-rate water pack (HRWP) in the two lower zones and an extension pack in the uppermost zone. This new approach helps make multizone cased-hole gravel-pack (CHGP) completions a more technically viable and cost-effective solution. Conventional CHGPs are limited to either stack-pack completions, which can incur high cost because of the considerable rig time required for multizone operations, or alternate-path single-trip multizone completions that treat all the target zones simultaneously, with one pumping operation. However, this method does not allow for individual treatment to suit reservoir characterization. The enhanced 7-in. multizone system can signi?cantly reduce well completion costs and pinpoint the gravel placement technique for each zone, without pump- rate limitations caused by excessive friction in the long interval system, and without any ?uid-loss issues after installation because of the modular sliding side-door (SSD) screen design feature. A sump packer run on wireline acts as a bottom isolation packer and as a depth reference for subsequent tubing-conveyed perforating (TCP) and wellbore cleanup (WBCU) operations. All three zones were covered by 12-gauge wire-wrapped modular screens furnished with blank pipe, packer extension, and straddled by two multizone isolation packers between the zones, with a retrievable sealbore gravel-pack packer at the top. The entire assembly was run in a single trip, therefore rig time optimization was achieved. The two lower zones were treated with HRWPs, while the top zone was treated with an extension pack. During circulation testing on the lowermost zone, high pumping pressure was recorded, and after thorough observation of both pumping parameters and tool con?guration, it was determined that the reduced inner diameter (ID) in the shifter might have been a causal factor, thereby restricting the ?ow area. This was later addressed with the implementation of a perforated pup joint placed above the MKP shifting tool. The well was completed within the planned budget and time and successfully put on sand-free production, exceeding the field development planning (FDP) target. The enhanced 7-in. multizone system enabled the project team to beat the previous worldwide track record, which was an HRWP treatment only. As a result of proper ?uid selection and rigorous laboratory testing, linear gel was used to transport 3 ppa of slurry at 10 bbl/min, resulting in a world-first extension pack with a 317-lbm/ft packing factor.