Hydraulic Fracturing Design Developments Towards Improved Effectiveness in North Kuwait Reservoirs

The North Kuwait Jurassic Gas (NKJG) reservoirs pose productivity challenges due to their geological heterogeneity, complex tectonic settings, high stress anisotropy, high pore pressure, and high bottom-hole temperature. Additionally, high natural fracture intensity in clustered areas play an important role in the wells hydrocarbon deliverability. These challenges are significant in field development starting from well design and stimulation up to production stages. The Gas Field Development Group (GFDG) are introducing for the first time in Kuwait new completion designs at high fracturing intensity; open-hole Multi Stage Completions (MSC), 4.5" Monobores and hybrid completions along with customized and efficient stimulation methods. This development strategy designed to overcome reservoir difficulties and enhance the well performance during initial testing and long-term production phases. At early stages of production, most of the wells were stimulated with simple matrix acidizing jobs and this method was sufficient to reach commercial production in conventional reservoirs. However, the reservoir depletion trend has negatively affected stimulation effectiveness and the wells performance in the recent years; hence, short and long-term solutions introduced to manage the sub-hydrostatic reservoir pressure. Our current focus is on the short-term stimulation solutions as they are relatively easier to apply compared to the long-term solutions that require additional resources, which are not available in the country. As a result, the stimulation methods, specifically the hydraulic fracturing treatments, increased production dramatically compared to previous years and it applied across North Kuwait Fields in conventional and unconventional reservoirs to reach the production targets of 2020-2021. The hydraulic fracturing treatment designs improved during the 2020-2021 fiscal year. The number of operations tripled compared to before and alternative chemical treatments with new fracturing designs implemented. In addition, these treatments executed across different well completions and reservoir properties. The objectives behind each fracturing treatment were different; for example: discovering new areas, re-stimulating under-performing wells, fracturing unconventional reservoirs, etc. Some promising wells did not flow as per expectation after matrix acidizing treatments despite the logs showing good reservoir quality similar to offset wells with good production. After re-stimulating with acid fracturing, the wells performed much better and one of them set a benchmark as the best producer amongst the offset wells. This paper evaluates the gaps in developing NKJG reservoirs, including fracturing treatments and highlights of the pros/cons for each operation, which in future supports the improvement of stimulation job designs. Moreover, it reveals the future requirements that control the operation success and how to reduce the well cleaning time post-fracturing in the event of low reservoir pressure. Finally, it describes how the outcome of the analyses directly assists reaching the production targets; since NKJG's production mainly depends on stimulation techniques.

Performance of sodium lignosulfonate as thickening additive in compositions for matrix acidizing of bottom hole zone

The work considers one of the promising directions for optimizing matrix acidizing using sodium lignosulfonate as a thickening agent. The mechanism of the interaction of acid solutions containing lignosulfonate with carbonate reservoirs is described. The use of sodium lignosulfonate in acid solutions solves several problems. Slowing the reaction rate allows the acid solution penetrate deeper into the formation, with maintaining the HCl concentration. The increased viscosity of the compositions increases the sweep efficiency of the bottomhole zone in the process of matrix acidizing. These two aspects increase the efficiency of matrix acidizing and the permeability of the bottomhole zone. In the course of this work, the chemical reaction rate of sodium lignosulfonate and hydrochloric acid solutions with carbonate core samples were evaluated. Sodium lignosulfonate in an acid solution reduces the dissolution rate of carbonate samples. It is assumed that slowing down the reaction rate allows the acid solution to form long high permeability channels which increases the efficiency of acidizing.

Acidizing Workflow for Optimized Well Performance in Zhdanov and Lam Oil Fields Offshore Caspian Sea

Successful sandstone matrix stimulation treatments require addressing complex mineralogy, correctly identifying formation damage, selecting the best stimulation fluids, and placing these fluids correctly. The objective of this paper is to demonstrate a workflow considering laboratory testing, advanced software modeling including acid and diverter fluid efficiency calibration using field experimental data, field execution, and relevant case studies in two oil fields located in the Cheleken block, offshore Caspian Sea. Implementation of the workflow has led to positive results. Matrix acidizing was selected as the primary method for restoring production of the oil wells drilled into sandstone reservoirs due to the reservoir characteristics. Deep Zhdanov wells and shallower Lam wells possess ~15 and ~250 md permeability and ~90 and ~50°C static reservoir temperature, respectively. The target rock mineralogy in both fields predominantly consists of quartz, chlorite, and carbonate minerals. Fluids selection, stimulation design and job execution followed the above mentioned workflow. Treatment modeling considered calibration factors derived from field testing and incorporated several acid and diverter systems. A mix of bullhead and coiled tubing placed treatments were employed. The first step of the workflow considered characterization of the rock mineralogy and selection of the best-fit treatment fluids. Rock dissolution and X-ray diffraction (XRD) tests were run to develop the optimum formulations for the treatment conditions. Further, the results of the laboratory testing were incorporated into the advanced matrix acidizing simulator to model and optimize the treatment schedules. The recently developed matrix stimulation software incorporates geochemical, thermal, and placement simulations calibrated with experimental data. Offset well stimulation treatment pressure match was done by calibrating the acid and diverter fluid efficiency, and those calibrated values were considered for design simulations for the following acid treatments. In this paper, the term "acid efficiency" is defined as a measure of the relative rate at which the acid can penetrate when it flows in the rock matrix as a function of matrix porosity and the overall acid reactivity. The term "diverter efficiency" is defined as a measure of the viscosity developed by a given diverter when it flows in the rock matrix. Such a calibration method accounts for the actual reservoir large-scale acid-rock reaction kinetics. Finally, diagnostic tests and main acid treatments were executed that enabled achieving the desired levels of skin reduction, reservoir placement, zone coverage, and hydrocarbon production rates. Several acid stimulation operations were conducted including three cases in which a low-temperature well with carbonate damage needed repeated acidizing and two additional cases that involved wells with deep, hot, and clay-rich pay zones. Several fluid schedules were applied including foam diversion technique. The above approach uses a unique method of acid efficiency calibration using field experimental data. It requires good knowledge of reservoir rock mineralogy, porosity, and permeability profiles in the zones of interest. Pretreatment skin is calibrated using production data prior to acid efficiency calibration based on matching the actual treatment pressures. The pressure behavior observed during the following treatments closely matched the design pressures confirming applicability of the approach.

Evaluation of Surfactant Mixture for Supercritical Carbon Dioxide Foamed Acid in Carbonate Matrix Acidizing

The effectiveness of matrix acidizing using CO2 foamed acid is dependent on the duration of foam stability. This paper presents a supercritical CO2 foamed acid with a surfactant mixture to improve the foam stability in carbonate matrix acidizing. The experimental apparatus was developed to conduct foam-stability and wormhole-propagation tests under high-pressure and high-temperature (HPHT) conditions. The foam decay times of five types of surfactants were measured under atmospheric conditions. Trimax (blend of cocamidopropyl betaine, disodium cocoamphodiacetate, and amine oxide) and Aromox C/12W (coco bis-(2-hydroxyethyl) amine oxide) had a high foam decay time. The surfactant mixture was prepared using these two surfactants. The foam stability tests of the surfactant mixture were performed according to the HCl concentration, surfactant mixing ratio, and injection rate of HCl under HPHT conditions. As a result, the foam stability could be improved by adding an HCl concentration of 20% to the surfactant mixture. Wormhole-propagation tests were performed using Indiana and Indonesian limestones. Because of the supercritical CO2 foamed acid injection, dominant wormholes were formed in all the core samples; thus, the absolute permeabilities significantly increased. The results of the scanning electron microscopy/energy-dispersive x-ray spectroscopy and thin-section analyses revealed that the number of large pores with pore sizes of ≥0.5 mm increased by the injection of CO2 foamed acid. Therefore, the supercritical CO2 foamed acid with the surfactant mixture exhibited a high efficiency of matrix acidizing in carbonate reservoirs.

First Successful Channel Fracturing Job, in the Middle East, Across Darcy-Permeability Sandstone Formation in Challenging Preperforated Liner Disposal Well Proves to be the Optimum Solution for Enhancing Injectivity

Produced water is a byproduct of the production cycle that often creates problems for handling and disposal. In Khafji Joint Operation (KJO), thousands of BWPD were being produced every day and disposed of by pumping the water back into the A formation. This formation is sandstone and has a permeability range over one Darcy. To improve the economics of this project, KJO set an injection target rate of 30,000 B/D per well at a maximum of 1,500-psi wellhead injection pressure due to surface facility constraints. Several completion and stimulation methods were selected to enhance the injectivity rate of these disposal wells. A pilot project was conducted to understand the best methods for injector well development. The well was drilled slanted across the reservoir to increase the reservoir contact area. Openhole and preperforated liners with different upper completion tubing sizes (i.e., 5-in. and 7-in. tubing) were compared to set the baseline of injectivity. Coiled tubing matrix acidizing and hydraulic fracturing were performed in this pilot well to enhance the injectivity. In each different methodology, a series of injection and surveillance tools was deployed to quantify the results. Upon completion with the 5-in. tubing, the pilot well could not achieve the target injectivity rate without well stimulation. An improvement after acid stimulation via coiled tubing was observed, although it was not able to achieve the injectivity target. Completing the well with 7-in tubing improved the injectivity rate slightly, but the injection pressure was still relatively high. Finally, and despite the combination of all challenges in this well, the first channel fracturing in a preperforated injector well in the Middle East was successfully performed. The post-fracturing evaluation shows that channel fracturing is the optimal stimulation method, increasing the injectivity index in this well ninefold compared to matrix acidizing. These results suggest that the implementation of effective fracturing design and operations improves the economics of the project. The results also demonstrate the importance of surveillance activities and their analysis to guide the technical decision and technology deployment. To overcome the challenges, a clear and robust workflow and solution execution and surveillance methods were developed. The pilot project illustrates the importance of having the right data to guide decisions and a rigorous QA/QC approach before, during, and after fracturing to achieve successful delivery.

A New Method of Carbonate Matrix Stimulation Modelling and Optimisation Using Field Experimental Data for Acid Efficiency Calibration and Case Studies in Kazakhstan

Successful carbonate matrix acidizing treatments require addressing pay rock mineralogy, produced fluid flow profile, selection of the best stimulation fluids, and correct placement of these fluids. A unique method of acid and diverter fluid efficiency calibration using field experimental data for treatment modelling and optimization has been implemented successfully in several mid-temperature reservoirs, including giant oil fields in Kazakhstan. Application of the technique led to positive results. Matrix stimulation is selected as the primary method for raising production from many carbonate reservoirs in the region because of the reservoir features. Coreflood testing conducted with candidate acid systems for selection and optimization of treatment fluid formulations and design schedules did not always lead to the desired post-stimulation skin levels, zone coverage, and production results. Hence, large-scale calibration of the acid parameters to the actual reservoir conditions was attempted. Treatment modelling in an advanced matrix acidizing software considered calibration factors derived from field tests. Thereafter, the optimized designs were implemented in the same reservoirs to improve the incremental production. Whenever possible, coreflood testing was carried out as the first step to determine the pore-volume to breakthrough parameters for the candidate acid systems. As the second step, these laboratory-derived data were used for modelling of the offset well stimulation design. Third, the actual treatment downhole pressure was matched with the simulated pressure by means of acid efficiency calibration in the matrix stimulation software. These calibrated parameters were then used for simulation of the following treatments in the same formation in attempt to model the expected reservoir placement and zone coverage more accurately and realistically to maximize the treatment effect. Post-stimulation fluid flow profile surveys have validated the optimized models and applicability of the methodology for improving incremental well productivity in the subject reservoirs. The stimulation approach uses a unique technique of acid efficiency calibration using field experimental data. It requires good knowledge of reservoir lithology and permeability and porosity profiles in the target zones. The initial skin is calibrated using pretreatment production data. Thereafter, acid efficiency is calibrated based on matching the actual stimulation job pressures.