Application of Time Lapse 3D/4D Seismic in the Monitoring of Steam Conformance and Cap Rock Integrity of Heavy Oil Thermal Production Project in North Kuwait

The challenge of Heavy oil thermal production Kuwait includes how to monitor steam flood effectiveness and cap rock integrity. Due to shallow & heterogeneous reservoirs and thin cap rock, pressurized and heated steam could diffuse in all directions and breach the cap rock. KOC acquired a baseline & time-lapsed surface seismic and 3D VSP for purposes of monitoring CSS production. This paper presents a technical application of seismic inversion to steam chamber size & cap rock integrity interpretation. The seismic image area includes 13 CSS wells, at varying CSS stages of steam injection, soaking and production. The data acquisition consisted of a base and a time-lapsed monitor seismic; each acquisition period lasting for around a week and separated by 40 day intervals. The simultaneous acquisition of surface seismic and the 3D VSP enabled complimentary data exchange and results validation. Well data of sonic and PHIT are used for building a low frequency inversion model. Rock physical modeling is also required to understand the effect of steam and production changes on acoustic and elastic properties. Various geophysical inversion methods are performed on AI inversion of post & pre stack seismic and Poisson's ratio inversion. To estimate reservoir temperature changes due to steam injection, the calibrated rock-physics model was utilized to relate the AI response to temperature change. The steam injection is expected to decrease acoustic impedance. The AI difference exhibits much wider impedance anomalies revealing steam chamber size and the production zone around the wells at various stages of the CSS cycle. Average temperature maps in reservoirs derived from rock-physical modeling also show temperature change around the wells. Inverted seismic attributes of acoustic impedance and temperature were used for study of cap rock integrity. Interpretation results of the steam size through AI and temperature analysis at reservoir and cap rock enable optimization of our CSS and SF completion strategies include steam pressure and volume, soaking period and thermal production control. The result of cap rock integrity monitoring also indicate no serious damage of cap rock under existing conditions of CSS operation (WHT: 420 °F & WHP: 320 PSI), which defines the limits of strategies to increase steam pressure and volume to increase EOR efficiency.

Application of Real-Time Geomechanical Modeling to Prevent Wellbore Instability While Drilling Horizontal Wells with Extended Reservoir Contact

Background Drilling deviated and horizontal high-pressure, high-temperature (HPHT) wells is associated with unique drilling challenges, especially when formation heterogeneity, variation in formation thickness as well as formation structural complexities are encountered while drilling. One of the major challenges encountered is the difficulty of landing horizontal lateral within the thin reservoir layers. Geomechanical modeling has proven to be a vital tool in optimizing casing setting depths and significantly increasing the possible lateral length within hydrocarbon bearing reservoirs. This approach ultimately enhanced the production output of the wells. In a particular field, the horizontal wells are constructed by first drilling 8 3/8" hole section to land about 5 to 10’ into the impervious cap rock just above the target reservoir. The 7" casing is then run and cemented in place, after which the horizontal hole section, usually a 5 7/8" lateral, is drilled by geosteered within the target reservoir to access its best porosity and permeability. Due to the uncertainty of the cap rock thickness, setting the 7" liner at this depth was necessary to avoid drilling too deep into the cap rock and penetrating the target reservoir. This approach has its disadvantages, especially while drilling the 5-7/8" lateral. Numerous drilling challenges were encountered while drilling the horizontal lateral across the hard cap rock. like severe wellbore instability, low ROP and severe drillstring vibration. To mitigate the challenges mentioned above, geomechanical modelling was introduced into the well planning process to optimize the 8 3/8" hole landing depth within the cap rock, thereby reducing the hard caprock interval to be drilled in the next section. Firstly, actual formation properties and in-situ rock stress data were obtained from logs taken in previously drilled wells in the field. This information was then fed into in the geomechanical models to produce near accurate rock properties and stresses values. Data from the formation fracture strength database was also used to calibrate the resulting horizontal stresses and formation breakdown pressure. In addition to this, the formation pore pressure variability was established with the measured formation pressure data. The porosity development information was also used to determine the best landing depths to isolate and case-off the nonreservoir formations. Combined with in-depth well placement studies to determine the optimal well trajectory and wellbore landing strategy, geomechanical modelling enabled the deepening of the 8 3/8" landing depth without penetrating the hydrocarbon reservoir. The geomechanical models were also updated with actual well data in real time and allowed for the optimization of mud weight on the fly. This strategy minimized near wellbore damage across the reservoir section and ultimately improved the wells productivity index. Deepening of the 8 3/8" landing depth and minimizing the footage drilled across the hard and unstable caprock positively impacted the overall well delivery process from well planning and drilling operations up to production. The following achievements were realized in recent wells where geomechanical modelling was applied: The initiative helped in drilling more stable, in-gauge holes across the reservoir sections, which were less prone to wellbore stability problems during drilling and logging operations.Downhole drilling tools were less exposed to harsh drilling conditions and delivered higher performance along with longer drilling runs.Better hole quality facilitated the running of multistage fracture completions which, in turn, contributed to increase the overall gas production, fulfilling the objectives of the reservoir development team.The net-to-gross ratio of the pay zone was increased, thereby improving the efficiency of the multistage fracture stages, and allowing the reservoir to be produced more efficiently.

Advanced Remedial Hydraulic Isolation by Perforate and Wash Technique

Well Cementing can be divided into two phases – primary and remedial cementing. Primary cementing may have 3 functions: casing support, zonal isolation and casing protection against corrosion. First two functions are commonly recognized while the third one might be a point of discussion, as the full casing coverage with 100% clean cement is not something common in most of the fields. In fact, poorly cemented areas of the casing may become negatively charged and create a zones of accelerated corrosion rate. This paper is about main role of cementing - zonal isolation. The process of primary cementing assumes that cement slurry is being pumped into the casing and displaced outside. After wait on cement time (WOC) it becomes hard, develops compressive strength and creates impermeable seal that ensures hydraulic isolation. Old and well-known technique, it still remains one of the most challenging rig operations. It is unlikely to find a service company that would guarantee 100% cement displacement behind the casing all the way from top to bottom. Main challenges in this region are quiet common for many other fields – displacement in deviated sections, losses before and during cementing, exposure to pressure during cement settling. In case the main target is not achieved (no hydraulic isolation behind the casing) – we may observe behind casing communications resulting in sustainable pressures in casing-casing annuluses. In this situation the remedial cementing takes place. It's function is to restore isolation so the cement can work as a barrier that seals off the pressure source. Despite of the good number of sealants available on the market (time, pressure, temperature activated) that can be injected from surface to cure this casing-casing pressure, Company prefers not to do so unless there is a proven injectivity capability that would allow for the sealant to reach deep enough, to protect aquifers in case of outer casing corrosion. Otherwise that would be just a ‘masking" the pressure at surface. Therefore in general Company prefers rig intervention to cure the pressure across the cap rock in between the aquifers and the reservoir. Those aquifers are illustrated on the Figure 1 below: More details on Company casing design, cement evaluation issues, sustained casing pressure phenomena and challenges have been mentioned previously [Yugay, 2019].

Underground Gas Storage Process Optimization Using Integrated Subsurface Characterization, Dynamic Modeling and Monitoring - A Case Study

Underground gas storage (UGS) will be key to addressing supply and demand dynamics as natural gas consumption grows during the coming decades in response to cleaner energy initiatives. The XGS facility began UGS operations in a depleted gas field located in SW China in 2013. Following this initial period of utilization, the site was reassessed to safely increase deliverability during winter months to meet future peak gas demand. The XGS field is located in a high tectonic stress region and has a structurally complex and highly faulted geological setting. The carbonate reservoir is heterogeneous and naturally fractured. Initial assessment steps involved determination of maximum storage capacity and estimation of required working gas and cushion gas volumes using fully integrated geological, geophysical, petrophysical frameworks. Geomechanical modeling was embedded into the analysis to determine the long-term impact inferred by cyclical variations of pressures on the reservoir performance and cap rock containment and evaluate both safe operating pressure limits and monitoring requirements. The coupling of complex reservoir and geomechanical parameters was required to create a dynamic model within the stress regime that could be history-matched to the early gas depletion phase and subsequent gas storage cycles. Such a holistic approach allows the operator to optimize the number of wells, their placement, trajectories and completion designs to ensure safe and efficient operations and develop strategies for increasing withdrawal rates to meet anticipated future demand. Additionally, tight integration of subsurface understanding with surface requirements, such as turbo-compressors, is critical to meet the UGS designed performance and deliverability objectives and ensure sufficient flexibility to optimize the facility usage. A further important task of the final phase of UGS facilities design involves enablement of sustainable operation through a Storage Optimization Plan. The results of the analyses serve as a basis for the design of this plan, in combination with fit-for-purpose surveillance systems of the reservoir and cap-rock seal recording pressure, rock deformation and seismicity in real time, along with regular wellbore inspection.

Temperature-Driven Hydrocarbon Generation-Expulsion and Structural Transformation of Organic-Rich Shale Assessed by in situ Heating SEM

Mud shale can serve as source or cap rock but also as a reservoir rock, and so the development of pores or cracks in shale has become of great interest in recent years. However, prior work using non-identical samples, varying fields of view and non-continuous heating processes has produced varying data. The unique hydrocarbon generation and expulsion characteristics of shale as a source rock and the relationship with the evolution of pores or cracks in the reservoir are thus not well understood. The present work attempted to monitor detailed structural changes during the continuous heating of shale and to establish possible relationships with hydrocarbon generation and expulsion by heating immature shale samples while performing in situ scanning electron microscopy (SEM) imaging and monitoring the chamber vacuum. Samples were heated at 20°C/min from ambient to 700°C with 30 min holds at 100°C intervals during which SEM images were acquired. The SEM chamber vacuum was found to change during sample heating as a consequence of hydrocarbon generation and expulsion. Two episodic hydrocarbon expulsion stages were observed, at 300 and 500°C. As the temperature was increased from ambient to 700°C, samples exhibited consecutive shrinkage, expansion and shrinkage, and the amount of structural change in the vertical bedding direction was greater than that in the bedding direction. At the same time, the opening, closing and subsequent reopening of microcracks was observed. Hydrocarbon generation and expulsion led to the expansion of existing fractures and the opening of new cracks to produce an effective fracture network allowing fluid migration. The combination of high-resolution SEM and a high-temperature heating stage allowed correlation between the evolution of pores or cracks and hydrocarbon generation and expulsion to be examined.

Breakthrough Pressure Prediction Based on Neural Network Model

The increasing carbon dioxide content is identified as the main cause of global warming. Capturing carbon dioxide in the atmosphere and transporting it to deep salt layer for storage have been proven and practiced in many aspects, which considered to be an effective way to reduce the content of carbon dioxide in the atmosphere. The sealing property of cap rocks is one of the key factors to determine whether CO2 can be effectively stored for a long time. In view of the disadvantages of tedious and time-consuming laboratory test methods for breakthrough pressure of cap rock, this paper explores the relationship between breakthrough pressure and other parameters such as porosity, permeability, density, specific surface area, maximum throat radius, and total organic carbon. The results show that the rock breakthrough pressure is closely related to the maximum throat radius and permeability determined by the mercury injection method, followed by the porosity and specific surface area, and less related to the density, depth, and TOC content of the rock itself. Then, with the selected parameters, a neural network model is established to predict the breakthrough pressure of cap rock, which can achieve good prediction results.

Introduction to this special section: Geomechanics

The term “geomechanics” means different things to different people. We assert that in the petroleum industry the broad consensus for a definition would probably be something like this: Geomechanics is the discipline that investigates rock mechanical behavior in the subsurface (i.e., at the wellbore wall, the overburden, cap rock, and/or the reservoir) under present-day in-situ stress and pore pressure conditions or those changed through human activity/intervention (e.g., production, injection, stimulation) during the life of a well.

In Situ Measurements of the Hydration Behavior of Compacted Milos (SD80) Bentonite by Wet-Cell X-ray Diffraction in an Opalinus Clay Pore Water and a Diluted Cap Rock Brine

Compacted bentonite is currently being considered as a suitable backfill material for sealing underground repositories for radioactive waste as part of a multi-barrier concept. Although showing favorable properties for this purpose (swelling capability, low permeability, and high adsorption capacity), the best choice of material remains unclear. The goal of this study was to examine and compare the hydration behavior of a Milos (Greek) Ca-bentonite sample (SD80) in two types of simulated ground water: i) Opalinus clay pore water, and ii) a diluted saline cap rock brine using a confined volume, flow-through reaction cell adapted for in situ monitoring by X-ray diffraction. Based on wet-cell X-ray diffractometry (XRD) and calculations with the software CALCMIX of the smectite d(001) reflection, it was possible to quantify the abundance of water layers (WL) in the interlayer spaces and the amount of non-interlayer water uptake during hydration using the two types of solutions. This was done by varying WL distributions to fit the CALCMIX-simulated XRD model to the observed data. Hydrating SD80 bentonite with Opalinus clay pore water resulted in the formation of a dominant mixture of 3- and 4-WLs. The preservation of ca. 10% 1-WLs and the apparent disappearance of 2-WLs in this hydrated sample are attributed to small quantities of interlayer K (ca. 8% of exchangeable cations). The SD80 bentonite of equivalent packing density that was hydrated in diluted cap rock brine also contained ca. 15% 1-WLs, associated with a slightly higher concentration of interlayer K. However, this sample showed notable suppression of WL thickness with 2- and 3-WLs dominating in the steady-state condition. This effect is to be expected for the higher salt content of the brine but the observed generation of CO2 gas in this experiment, derived from enhanced dissolution of calcite, may have contributed to the suppression of WL thickness. Based on a comparison with all published wet-cell bentonite hydration experiments, the ratio of packing density to the total layer charge of smectite is suggested as a useful proxy for predicting the relative amounts of interlayer and non-interlayer water incorporated during hydration. Such information is important for assessing the subsequent rates of chemical transport through the bentonite barrier.