Handil field is a mature oilfield located in East Kalimantan Indonesia, operated by TOTAL E&P Indonesie (TEPI). By 2012, there were several wells completed with Gravel Pack completions that were producing sand during production phase. This condition created a hydrocarbon production limitation around 3700 bopd from three oil wells. TEPI were looking at technical solutions to improve well performance. Within the solution options that exist, chemical treatments - that consolidate the near wellbore area - can be a viable alternative for a number of completion types. Chemical sand consolidation can give a formation additional residual strength. This can enhance a maximum sand free rate (MSFR). One chemical treatment developed is environmentally acceptable by North Sea standards and simple to deploy by in a ‘one pass’ pumping operation. Looking at the completion type and complication during sand control remediation pumping, this chemical was finally chosen. The simpler deployment operation, since there is no overflush, induces less risk during pumping the treatment. The active chemical reacts with connate water in the near well bore area and forms a polymerized network around and between the sand grains. This network imparts additional residual strength allowing the near well bore formation to withstand greater drawdown and fluid flow. This paper discusses the experiences of TEPI with respect to using the organo-silane based chemical treatment in Handil field, Indonesia. A well intervention campaign treats a number of production zones which were treated separately by sliding sleeve door (SSD) selection. To ensure liquid cleanliness prior injection into formation, the use of coiled tubing was required and the treatment programs were adjusted from standard designs to accommodate this. Most of the operation performed resulted in an increase of the MSFR (leading to production increase). One job result however was not as per expectation. The lessons learnt from these treatments and improvements in candidate selection will be discussed here. This first coiled tubing application of the organo-silane based chemistry and the need to manage multiple small batches of the water sensitive treatment in a humid and wet environment were challenges to overcome.

Mahakam block with one of its gas fields, Tunu, has been developed for decades. Hundreds of wells were drilled to unlock layered sand reservoirs ranging from unconsolidated to consolidated reservoirs. Through field experience, well architecture is actively developing. The latest architecture, targeting shallow reservoirs only, is called Shallow Light Architecture (SLA). The well is completed with 3.5in production tubing cemented inside a 8.5in open-hole reservoir section. SLA is the default architecture for chemical sand consolidation (SCON) or thru-tubing screens as subsurface sand control. Perforation is performed by deep penetration (DP) hollow-carrier guns deployed with double-density to maximize open area and reduce sand production risk. DP charges were used based on the requirement to bypass near-wellbore damage, which is the same practice used in consolidated sand reservoir perforating. As more marginal reservoirs need to be unlocked, big entrance hole (BEH) perforation was initiated for the current sand control optimization alternative by SCON chemical reduction with shorter perforation intervals; and for thru-tubing metal screen performance improvement by placement in front of perforation entrance tunnels with minimum erosion risk. BEH was then studied as it has never been used previously in Mahakam with thru-tubing applications. Simulation and pilot well trials were explored to ensure that a short penetration would not significantly impact reservoir delivery on SLA wells. Inflow performance relationship (IPR) analysis resulted in slight additional drawdown compared to the calculated drawdown using DP at 2.5 MMscfd as an average gas rate in current thru-tubing sand control, which was considered acceptable from the operating envelope perspective. In total, BEH perforation was executed on ten wells with reservoir permeability range from 220 millidarcy (mD) to an extreme case of 3000 mD. Various SCON treatments were injected at optimized perforation lengths by cutting chemical costs up to 60% with sand-free production at a particular parameter and chemical type. On the other hand, in the application using screens, evaluation was not conclusive due to screen sizing issues for some installations. However, in-situ gas velocity could be reduced to the theoretical erosion velocity limit for a metal screen. This new approach to BEH charges utilization has a potential solution optimizing current SCON costs while also reducing erosion risk for the through tubing screen application to improve its performance. By using short penetration of charges, this approach was successfully implemented without jeopardizing reservoir's deliverability.

The Mahakam delta in east Kalimantan, Indonesia, yields gas as the main hydrocarbon production with giant reservoirs ranging from shallow to very deep zones. Reservoirs consists of clean sandstone with high permeability. Due to the field maturity, production gradually moved from the deep, consolidated zones into very shallow, unconsolidated zones. Sand production often causes significant problems at the surface when the well is online. The best approach to sand control is to keep it inside the reservoir, because it could create problems not only at surface but within the wellbore as well. Sand consolidation has been a common approach applied in Mahakam field for more than a decade. Several products have been utilized, including laboratory testing and field trials. The case history is based on a well that had been treated using 2 different sand consolidation products in the past, but both eventually produced inadequate results. Sand continued to break through after each treatment, hence the reserves could not be drained in full. Since the reservoir still had promising reserves, another remedial sand consolidation treatment was planned. This treatment was executed by utilizing a tension packer with a J-slot mechanism in order to focus injection of the resin into the zone of interest. Additionally, there was a challenge with another open zone above the subject interval. The remedial sand consolidation treatment using a resin-based chemical delivered excellent results. Even though this reservoir had been exposed to 2 different chemical treatments in the past, by using the resin-based sand consolidation product, the well was still able to be produced at target rates without sand production. In conclusion, resin-based sand consolidation solutions can unlock prolific reserves that may have been a significant challenge with traditional methods.

In accordance with the cost-saving campaign in Mahakam block, sand consolidation was successfully developed as a cheaper alternative to sand control. Despite the limited development of sand consolidation market and the successful application of sand consolidation products from the current incumbent, Company faces the risk of limited access to other products and potential failure to switch existing products. However, self-validation for any desired product with lower risk exposure is considerable. Taking all the necessary lessons learned during initial product development, the successful application of sand consolidation depends on proper control of product deployment rather than the product composition itself. The systematic arrangement of all controlled parameters generates a causal relationship, which will act as a validating workflow to the other 3 new products. During the deployment of these products in 17 wells, all parameters were successfully controlled and it was possible to make the wells producing with a success rate of more than 90%. Based on this study result, Company will have more flexibility in using sand consolidation products variation by considering the associated resources: attractive pricing, contractual fairness, and logistic access.

Declining of shallow reservoir reserve urges efficiency effort to switching well architecture from zone-selective gravel pack completion to non-selective tubingless completion. However, zone management in tubingless completion is not as simple as sliding sleeve manipulation in gravel pack well. It requires proper zone isolation of closed zone such as setting plug, tubing patch, or squeezed cement. Therefore, optimum zone management need to be identified to be consistent with cost efficiency effort. Study in determining optimum zone management captured two nearly identic case of 3 zones of selective well and non-selective well. The well cost, production, and its net present value was compared to evaluate how the reservoir production is managed. Although selective well has higher initial well cost, but operation cost during the production is significantly low. On the other hand, even non-selective well has lower initial well cost, due to complication on zone management, non-selective well has higher operation cost. The total cost of problematic non-selective well could nearly reach the selective well cost. The complication is identified as downward movement, i.e. re-accessing previously isolated lower zone and isolating upper zone at once. However, this study suggests that strictly following bottom-up production strategy could potentially avoid the complication by 23% more efficient in production and cost index. Well cost efficiency is not only determined by lower initial well cost. All operating cost during production must be also considered. Optimum well management for both type of completion is a key parameter in order to control the cost efficiency effort. Therefore, well completion design selection must consider not only the cost and production, but also the operation excellence and capability during managing well production in its lifetime.