This paper describes the deployment of Autonomous Inflow Control Valve (AICV) technology in an oil producing well affected by gas breakthrough, to reduce gas production and increase conformance. Based on the fluid properties, AICV differentiates the fluid flowing through it and can autonomously choke / shut off gas inflow from the high gas saturated zones, while allowing oil production from healthy oil-saturated zones. The subject oil producing well has open hole section of over 3200ft. A multidisciplinary data integration of well logs, production history, and subsurface geological description is considered for modelling and designing optimum AICV completion. The main objective is to restrict the gas breakthrough to a smaller compartment, allowing other compartments to produce at higher oil production. The AICV completion was run with a remote actuated shoe to enable fluid circulation from the end of downhole completion string while run-in-hole. AICV technology allows pro-active reservoir management. It shuts-off the gas at subsurface level autonomously, without any intervention. Due to the chocking effect, AICV allows sustain the well production within the reservoir management guidelines, with improved well availability and reducing the operating expenditures. This has an additional positive impact on the environment due to reduction of gas flaring as AICV is expected to reduce the gas production/GOR by 81% This paper discuss in detail how the AICV completion offered a technically attractive and cost-effective gas management and production optimization opportunity. Futures implementation of this solution will improve Miscible Water Alternating Gas (MWAG) injection efficiency and gas recycling in addition to reducing the carbon footprint per barrel of produced while sustaining production.

Reservoir heterogeneity, presence of faults, lower coiled tubing (CT) injection rates, precise fluid placement, and uncertainty of downhole dynamics are the major challenges for matrix stimulation of openhole horizontal water injector wells completed across tight carbonate reservoirs in the onshore Middle East. The stimulation strategy implemented over the past decade to address those challenges was deemed ineffective, often leading to a rapid decline in injection rates after the treatments and, therefore, frequent restimulation. Since 2019, a different intervention approach has been implemented, leveraging a workflow based on CT equipped with fiber optics for real-time downhole telemetry and distributed temperature sensing (DTS). Results to date have been encouraging, yielding significant injectivity gains along initial trials. The workflow recently evolved with the inclusion of petrophysics and seismic data during candidate validation to determine a baseline zonation of the openhole section. This critical new step in the stimulation strategy is made necessary by the presence of faults or high-conductivity streaks, whose presence require additional engineering of the fluid placement to avoid early water breakthrough in the producers. During job execution, after the wellbore has been conditioned using a high-pressure rotary jetting tool, DTS surveying is conducted to confirm the conductivity of faults crossing the uncased section and determine the distribution of high- and low-intake sections along the open hole. Adjustment to the pumping sequence—including zonal coverage, volumes, and diversion techniques—are decided based on that information. The prestimulation injection profile, together with petrophysics and seismic data, enables segmenting the open hole into intervals requiring different levels of stimulation, so each section can benefit from a customized treatment that increases injectivity and improves uniformity of injection. Complementary fluid placement techniques and diversion requirements, such as dual injection, are also identified at this stage and generally determined by the level of conductivity of the fault system detected with DTS. During the stimulation stage, fiber-optic telemetry is used to optimize jetting pressure and monitor downhole pressure in real time to ensure fracture pressure is not exceeded. Upon completion of the acidizing stage, another DTS acquisition is conducted to assess the poststimulation injection profile. The workflow enables incremental assessments through the course of the operation, adding flexibility to the operational sequence and the possibility to repeat steps when the expected injectivity gains are not achieved, or a new segmentation of the open hole is required. This reinvention of the matrix stimulation workflow brings new perspectives for acidizing openhole horizontal tight carbonate water injectors featuring highly conductive streaks or faults. Using this methodology can significantly improve results over conventional practices more than twofold based on initial results. It is particularly adapted to wells where reservoir heterogeneities lead to nonuniform injection profiles and the risk to unbalance pressure support in the formation.

This paper is based on the analysis of miscible WAG for an onshore Middle-East field, with strongly undersaturated light oil. Water Alternate Gas operations have been ongoing for around 5 years, which is relatively recent compared to more than 40 years of production history. Goal of this work was to assess the efficiency of this miscible hydrocarbon WAG and to optimize it on the different compartments, with respect to miscibility, voidage replacement, and recycling. As this is a large mature field, with WAG operations dispatched on around 50 injectors and 9 fault blocks (compartments), the method of analysis had to be robust with respect to the different injection strategies followed in the past. It was essentially based on injection and production data, but also used pressure data when available. We computed the following dimensionless variables: oil recovery factor, BSW, voidage replacement ratio (VRR), and also WAG ratio and gas recycling ratio (GRR). Their evolution versus time was analyzed and compared between fault blocks. Using dimensionless variables allowed to compare fault blocks with different initial volumes in place, and to illustrate trends versus time. It was also found beneficial to lump some compartments, when communication was substantiated by pressure data. On the production side, we used the conventional BSW and GOR variables to quantify the water and gas recycling ratio. On the injection side, we observed that in some compartments, the historical WAG ratio was too low in the oil zone, which could be quantified by excluding the peripheral water injection volumes. The analysis allowed also to estimate the gas utilization factor and efficiency, which confirmed the overall high efficiency of miscible gas injection in 3-phase mode. It was also found that the injected fluid efficiency correlated with geology: gas injection tends to be more efficient in zones with high permeabilities at the bottom (coarsening downwards), while water injection is better adapted to zones with high permeabilities at the top (coarsening upwards). Estimating these water and gas efficiencies also allowed to optimize the injection strategy on a field level, by comparing the water efficiency with other units of the field only under waterflood.