In high pressure high temperature (HPHT), deep sour gas condensate and volatile oil fields, in which the wells contains approximately 2 – 8 % H2S and 1 – 2.5% CO2 it is necessary to evaluate the corrosion rates for the downhole completion string. As it is well known that, corrosion leads to several major problems which affect the well integrity and the production sustainability through the production string failures and tubing casing pressure communication. The purpose of this paper is to illustrate an initial monitoring plan to extend the life of a completion string, reduce the number of well interventions and workovers due to corrosion and scale deposition. This systematic approach will improve the future tubing selection criteria and evaluate the need for CRA material also enhancing the downhole inhibition system with reference to KOC safety regulations from operational and economical prospective. The conclusions of the above will be based on data collected from 13 wells to investigate the key factors which accelerate the corrosion occurrence and rate. As such, a detailed analysis was constructed by using the baseline corrosion logs and their outputs such as time lapse, pitting, and fluid properties vs. metallurgy.

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.

Selecting the completion design and stimulation technique in North Kuwait Jurassic Gas (NKJG) were critical to overcome reservoir challenges by stimulating these unconventional formations efficiently and effectively. Therefore, the completion design must be high-pressure rated upto 15,000 psi, high temperature of 275°F and sour service specified because of high H2S & CO2 content. These reservoirs are heterogeneous carbonate type with various productivity index due to existence of natural fracture which needs proper completion type that treat each reservoir layer separately. The most challenging factor in these unconventional reservoirs is the high permeability contrast among the different flow units because of the dual porosity effect which needs convenient diversion mechanism during the stimulation. The reservoir was segmented into different intervals to enhance the productivity index of each flow unit. For that reason, "High Rate Matrix Acidizing (HRMA)" method was obtained with retardard acid to restore the well productivity due to the drilling fluids which alter the effective permeability near the wellbore. By dividing each flow unit into separate stages across packer system and stimulate them subsequently is the aim to overcome high permeability contrast across the reservoir flow units. The Monobore Multi-stage was chosen as a completion type to produce from different zone of interest. These Reservoirs are divided into different stages and acid treated with various stimulation techniques (Acid fracturing & High Rate Matrix Acidizing). The success of the stimulation treatment in monobore Multi-stage completion depends on several factors such as: selecting proper fluid recipes, rock/fluid properties, job design, and field implementation. That type of completion is activated as a drop-ball system to stimulate each flow zone individually but in single well intervention setup. This paper presents a 15K open-hole HPHT MSC field success case application that describes the best practices, learning, planning, design, installation and stimulation in NKJG unconventional reservoirs to enhance well performance and overcome reservoir challenges. An improvement in understanding of production performance from several reservoir sections is the key enabler selective stimulation and effective testing. After stimulating all the stages milling of the ball seats of completion was obtained in order to pinpoint well production profile. The post stimulation flow tests results and production logs provided a good evidence for applying this technology these unconventional reservoirs.

Achieving sustainable gas and condensate production from carbonaceous North Kuwait Jurassic Gas (NKJG) reservoirs has been challenging due to multi-dimensional inflow/outflow complications under restrictive operating downhole conditions. Production from the NKJG reservoirs has strategic importance for the State of Kuwait, where the formations are deep and sour, and produce gas-condensate and volatile oil, in which the produced fluids contain from 2 to 8% H2S and 1 to 3% CO2. High reservoir pressure of up to 12,000 psi is widespread trapped below an over-pressured salt structure. NKJG reservoirs have high temperature of ~275°F and have been recently completed with monobore completions, to optimize overall commingled well performance and to ensure operational optimization of future well interventions. Differential depletion has had significant consequences in well and reservoir management including the design and execution of stimulation treatments, particularly the "high rate matrix acidizing (HRMA)" applications. In addition, vertical variations in lithological and mechanical rock properties contribute to drilling challenges which are progressively exacerbated as the deepest zones continue to produce most of the hydrocarbons whereas other potential horizons are not exploited at similar rates. Monobore completions have been deployed so that each flow unit could be segregated and stimulated separately, starting from the bottom, moving uphole as each stage is treated, activated, tested and isolated using drillable bridge plugs. After all zones are completed, the bridge plugs are drilled out using coiled tubing mills and commingled production is established from all zones. To overcome this complex technical challenge while utilizing the funds and resources efficiently, the team in charge of the project developed a novel method of assessing the zones similar in reservoir characteristics and generated a "bullheaded HRMA treatment design" concept which was applied in the subject well while stretching the length of the perforation interval to a gross 216 ft that can be effectively covered with sound wellbore diversion methodology using particulate chemical diverters as well as leak-off control diverters. The custom-designed fluid train was tailored to effectively stimulate each conductivity unit, followed by diversion into the subsequent stages. The perforated interval length has been stretched to 285 ft in subsequent wells based on the success of this well. The completion and intervention history of the subject well is covered in this paper followed by the successful field implementation of the HRMA application as a case study, and to share the learnings and recommendations providing pre-stimulation and post-stimulation production logging comparisons. As an additional challenge, the HRMA treatment overcame the heavy near-wellbore damage created during a workover fishing operation due to the well-kill with heavy drilling fluid. The results are confirmed by calibrated nodal analysis assessment providing evidence of the success in deploying this technology in unconventional tight gas reservoir of less than 10 mD permeability. Achieving optimal inflow distribution along vertically varied flow zones has enabled the asset to deploy this systematic approach in other new wells in the NKJG while saving significant cost and time.