This paper demonstrates the production optimization methodology being used by Kuwait Oil Company Jurassic gas that added significant contribution of approximately 37% of total field incremental production gain in 2021. Production optimization is a continuous iterative process to improve production, especially in mature fields. The North Kuwait Jurassic Gas field’s team has adopted an integrated enhanced and structured process to identify opportunities for production optimization with a pro-active approach focusing on flowing wells and rig-less interventions to tackle production challenges and achieve production targets. The Jurassic gas asset has unique mature-field challenges. It produces mainly from deep (up to 19,000 ft MD) high pressure and temperature, conventional and unconventional tight carbonate reservoirs, highly deviated to horizontal wells, different completion configurations (4.5in monobore, 3.5in × 5in liner, and 4.5in Multi-stages completions), wellbore cleaning and accessibility, scaling and flow assurance, high heterogeneity and permeability contrast among different flow units and dual permeability effect (matrix and natural fractures), production decline due to pressure depletion, liquid loading, high H2S (up to 13 mol%), surface production facilities limitations (e.g. limited MP and H2S handling capacity). effectiveness of subsequent stimulation treatments of such complex heterogeneous reservoir to improve well productivity and connect the natural fractures. The recovery from such complex heterogeneous reservoirs is extremely challenging if conventional development strategies are applied and need for appropriate production optimization methodology outlined here. The Heterogeneity Index process is utilized to rapidly demonstrate production gain opportunities via quick screening method of identifying preliminary candidate wells with anomalous behavior (over/under performance) for further analysis. The results from this screening tool were utilized to identify the families of type productivity problems at field and well levels with solution categories for production enhancement. Representative wells were selected for detailed diagnostics based on the relevance and size of productivity impact and the potential of its well deliverability. Once a few "top potential" wells were identified, production engineering workflows were implemented to assess and forecast the potential of production increase and to determine and evaluate the best solution design and intervention action. Detailed production optimization process provided recommendations of various remedial intervention solutions to improve well production potential via productivity enhancement ranging from complex matrix and fracturing stimulation, additional and/or re-perforations, wellbore cleaning, flow assurance solutions, to choke management. Other advanced technologies were applied to improve various strategies, including completions, perforation, stimulation, and production control. The executions of recommended interventions added significant contribution of approximately 37% of total field incremental production gain in 2021. Such production optimization process, experience and lessons learned will be shared where it can be used in analog fields.
Producing hydrocarbons at appraisal and development targets from deep, sour, over-pressured and HPHT carbonates in North Kuwait has been a challenge driven by the complex reservoir heterogeneity as well as the damage induced by the use of barite-laden heavy oil-based mud (OBM) in drilling and during installation of production tubing as completion fluid. Due to the tight formation properties and the added damage induced by OBM, matrix acidizing does not always deliver hydrocarbons at economic rates. Such zones require hydraulic fracturing under challenging conditions imposed by the wellbore limitations, such as high degree of deviation, smaller tubing as the frac string, and length limitations of the seal-bore assembly, as well as the on-site presence of a deep drilling rig to complete the tests effectively and on-time. Tubing conveyed perforation (TCP) and wireline perforation techniques require wells to be subdued prior to the installation of final completion due to the over-pressured reservoir conditions and requirement to perforate with as large guns as possible. Both of these techniques have proven less then efficient as the flow tests performed before and after running final completion historically indicated significant drop in production of hydrocarbons. Therefore, a gun hanger shoot-and-drop perforation system was customized to facilitate underbalance perforation and immediate well clean up with no further well-kill requirement whilst still utilizing optimum gun size for better perforation geometry. As an added challenge, the requirement to hydraulically-frac the tight carbonates necessitated modeling and design of tubular movement, stress analysis & drag modeling in the highly deviated case described in this paper. Determining the operational pressure envelope to complete the hydraulic frac treatment safely and effectively (operations pressure management) was the critical success factor in the placement of large acid hydro-frac without jeopardizing the wellbore (PBR seal) integrity. Customized "surfaceadjusted" weight of tubing slack off methodology was developed and implemented, resulted in maintaining safe operational conditions during the hydro-frac where the wellhead treating pressures exceeded 13,000 psi. Because of the specific perforation technique and analytical approach required for optimal treatment pressure management, a complex data-frac program followed by a large and customized acid hydro-frac program were successfully implemented with the facilitative function of the deep drilling rig on the well site. Collection of critical completions data was achieved and the reservoir deliverability was established while wellbore integrity was maintained. Mechanical formation properties were determined and hydro-frac geometry on effectively connecting to the higher mobility segments of the reservoir was realized. This paper will also outline the future optimization plans based on the learnings from the frac tests conducted in the well.
The North Kuwait Jurassic Gas (NKJG) reservoirs are currently under development by KOC with assistance from Shell under an Enhanced Technical Services Agreement (ETSA). The fractured carbonate reservoirs contain gas condensate and volatile oil at pressures up to 11,500 psi with 2.5% H2S and 1.5% CO2. This paper describes the planning and implementation of a Well Integrity Management System (WIMS) that allows the safe management of the wells that are being drilled in this hazardous environment.The wells are designed and constructed in accordance with KOC standards and on transfer of ownership from Deep Drilling Group to Production Services Group have their integrity managed under WIMS. The system is a structured process, relating the frequency and extent of routine monitoring and testing to the particular risks associated with the wells. Compliance with WIMS requirements are routinely reported so that all are aware of the current state of well integrity. WIMS is initially managed through simple spreadsheets and during 2012 is being integrated into KOC's Digital Field infrastructure.Initially, WIMS has been applied to the range of wells 'owned' by Production Services Group and tests currently carried out by Well Surveillance Group under PSG's direction. In order to realise the full assurance of safe operation the scope of WIMS application is being extended to the full well population, including suspended wells, and the full range of tests required.Implementation of WIMS will allow KOC (NKJG) to be able to state that 'our wells are safe and we know it'.
Deep HP-HT sour carbonate reservoirs in Northern Kuwait have varied matrix properties and fracture intensities. The wells are drilled with barite laden OBM with 1,000-2,000 psi overbalance. The intervals suffer substantial formation damage during drilling as is evident from the fact that the wells normally do not get activated, in spite of creating an underbalance of 5,000-6,000 psi by displacing mud with a lighter fluid. During the early exploration phase of these reservoirs, long and/or multiple intervals were perforated and treated with conventional matrix stimulation using 28% retarded/ emulsified acid in stages with chemical diverter (gel based and visco-elastic surfactant based). Post stimulation PLT survey in these wells indicated, that only about 5-10% of the total perforated interval contributed to the production; concluding that the diverters were found to be ineffective leading to sub-optimal reservoir management due to poor zonal contribution. As part of strategic reservoir management process selective bottom up approach in perforation with higher concentrations of HCl treatment and without diverter has been adopted in these reservoirs. To obtain a degree of diversion over the perforated interval, the acid was pumped at higher rate and with higher pressure. Adoption of this changed perforation and stimulation treatment has been proved to be the key enablers for improving zonal productivity. Around 30 wells have been completed with this changed perforation strategy and treated with this new recipe and technique. Post stimulation test results are comparable to those wells treated with regular matrix stimulation. The PLT survey post acid wash treatment by this technique showed that zonal contribution has improved. This process in addition to being simpler is faster and cost effective. This paper presents the comparison between the two types of perforation and stimulation strategies vis-à-vis test results and also the QA/QC followed prior to pumping the acid.
The first ever CO2 foam fracturing new technology in Kuwait Oil Company (KOC) history was executed flawlessly in late 2021. Three treatments were executed. Co2 Foam Fracturing proved its significant added value of improving productivity in deep depleted tight carbonate Jurassic reservoirs, enhance flow back, reduce water consumption and carbon emission, and enable early production plus improving operation efficiency and cost saving. The stimulation operation has proven to be a huge success for all multidisciplinary teams involved as preliminary results showed over 50-70% production increase compared to offset wells. The main challenges of acid fracturing stimulation in depleted reservoirs are the need for extended formation cleanup to flow back the injected fluids via prolonging Nitrogen lift that add higher operational costs and intervention operations. Therefore, energetic high foam efficiency frac fluid becomes essential to assist flowback and retrieve pumped frac fluids from reservoir. To tackle these challenges, Carbon Dioxide CO2 is pumped in liquid phase as energetic fluid together with normal frac fluids. Due to CO2 liquid nature, high foam efficiency can be reached (40 – 50%) at much lower friction losses. So, it enables achieving pumping frac at high rates and high foam efficiency. The main benefits of CO2 Foam frac are better fracture cleanup due to expansion of the stored compressed gas in the liquid CO2, fluid loss control that is provided by foam, minimized fracture conductivity damage, and the increase in hydrostatic pressure while pumping that translates to lower surface pressures during injection. The selected pilot well is in depleted deep tight carbonate reservoir area of North Kuwait Jurassic gas fields. The executed acid fracturing operation required close planning starting from Q1-2021. Many challenges faced from logistical issues, lack of infrastructure and CO2 resources for the multi-faceted operation due to COVID-19 pandemic limitations. These challenges were tackled ahead with the integration of technical and operations teams to bridge the knowledge gap and to enable executing the operation safely. The pilot well's net incremental production gain is estimated at 50-70% compared to offset wells, with improved flowback and formation cleanup with less well intervention. The resulting time and cost savings as well as the incremental well productivity and better operation efficiency confirmed high perspectives for the implemented foam acid fracturing approach. Another two CO2 Foam acid fracturing wells were executed with good results too. This paper will demonstrate the value of CO2 foam fracturing in depleted reservoir and KOC experience post first application and its plans to expand CO2 Foam Fracturing application across KOC different fields.
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