Wellbore Integrity and CO2 Sequestration Using Polyaramide Vesicles

A new cementing additive is chemically engineered to react with formation fluids that act antagonistically towards cement. Engineered polymer capsules house encapsulants to react with antagonistic gases downhole like CO2 to form a more benign and beneficial material. Embedded in cement, the polymer capsules with semi-permeable shells allow fluids to permeate and react with encapsulants to produce beneficial byproducts, such as calcite and water from CO2. Reactivity between the encapsulant and antagonist gas CO2 is demonstrated using thermal gravimetric analysis (TGA) and other tests from oilfield equipment. When cement fails, casing-in-casing events, or CCA, causes antagonistic gases like CO2 to migrate to the surface. Embedded in the cement for such moments such as cement failure, additives housed within polyaramide vesicles chemically and physically intersect CO2 from gas migration events. The shape of the polyaramide additive is unique and versatile. Furthermore, because the material is polymeric, it imparts beneficial mechanical properties like elasticity to cement. A vesicle in form, this polymer allows the manufacturing of new cement additives for applications such as increasing the integrity and sustainability of oil well cement. Data also shows production of calcite by the bulk of the material. This technology applies to CO2 fixation and self-healing cement using reactive polymer vesicles.

Wellbore Integrity: An Integrated Experimental and Numerical Study to Investigate Pore Pressure Variation during Cement Hardening under Downhole Conditions

Summary Understanding the cement hardening process and determining the development of the state of stress in the cement under specific downhole conditions are challenging but fundamental requirements to perform an accurate prediction of wellbore integrity. As an essential component of the state of stress, the temporal variation of cement pore pressure is a critical factor that affects the occurrence of cement failure. In this study, we present a novel laboratory setup to measure the cement pore pressure variation during hardening under representative downhole conditions, including the pressure, temperature, and water exchange between the cement and formation. The pore pressure measurements are further incorporated with a staged finite element analysis (FEA) approach to investigate the state of stress development during cement hardening and to evaluate cement failure under different operations and after different wait-on-cement (WOC) periods. The laboratory measurements show that the external water supply from the formation significantly impedes the pore pressure drop in the cement. The numerical results indicate that the accelerated pore pressure decrease obtained without considering downhole conditions elevates the contact pressure at the cement-formation interfaces significantly and moderately increases the von Mises stress in the cement. The numerical results further predict that the accelerated pore pressure decrease leads to an overestimation of shear failure during pressure testing and steamflooding operations but an underestimation of debonding failure during severe fluid loss and injection-related cooling processes. Based on the results of the integrated laboratory and numerical approach, qualitative and quantitative suggestions are provided for field operations to inhibit wellbore integrity risk during the wellbore life cycle.

Making Workovers Easy and Cost Effective: Turning Old Ways into New Opportunities

A case study and methodology is presented to shed the light on the different processes followed during the placement of a non-damaging isolation barrier in a group of highly naturally-fractured and vugular gas wells. The temporary isolation aims at isolating the wellbore from the troublesome formation and allow the removal of the original completion string and install a new redesigned one. The process helped putting the wells back on production with-out the need to stimulate any of them. This helped client to reduce the overall workover cost by 40% and proved to be successful and efficient to complete the required operation in a time-efficient. The operator had 4 wells with OH sections ranging from 40-80m which were completed in the late 1990's with no production packer. To preserve wellbore integrity the completion string needed to be pulled and replaced by a string with production packer and DH gauges. Visco-Elastic Surfactant (VES) and calcium CaCO3 (carbonate) used ubiquitously in field operations were tested for optimal design to fill highly fractured OH without damaging formation. Caliper logs were not available, and the presence of natural fractures posed a challenge to calculate the actual OH volume. A system was developed to carry the CaCO3 into the wellbore in stages and slickline was employed to measure fill after each stage. Once the OH was filled with CaCO3 and well would support a fluid column coil tubing was used to place an acid-soluble cement plug in the short interval between casing shoe and end of tubing (6-9m). The paper describes the optimization process followed to tune the CaCO3 pads composition, gel composition, mixing and placement technique. The first well in the campaign required more than 10 times the theoretical volume of CaCO3 to fill the open hole with multiple settling issues at surface. It was concluded the surfactant gel was likely carrying the CaCO3 into the fractures. The procedure was modified to tie in a line of breaker solution to the well head allowing sufficient viscosity of the fluid to carry the CaCO3 from surface but immediately lose viscosity and allow the CaCO3 to settle in the open hole without being carried into the formation. Specific coil tubing procedures were employed to allow the setting of ultra-short acid soluble cement plugs (<6m). All wells were successfully isolated to allow the safe workover of the completion string and returned to production with no loss of gas flow, with-out the need to stimulate after the work over. The campaign exhibited a new method of employing existing technologies to achieve the objective in a highly challenging and relatively new oilfield of Kurdistan. The campaign also demonstrated the benefit, in terms of saving time and cost because of extensive pre-execution planning.

Sealant injectivity through void space conduits to assess remediation of well cement failure

The primary cement of oil and gas wells is prone to fail under downhole conditions. Thus, a remedial operation must be conducted to restore the wellbore integrity and provides zonal isolation. Many types of materials are currently used and/or have the potential to be employed in wellbore integrity applications, including, but not limited to, conventional Portland cement, microfine and ultrafine cement, thermoset materials, and thermoplastic materials. In this study, several types of materials were selected for evaluation: (1) conventional Portland cement, which is the most widely used in remedial operations in the petroleum industry, (2) polymer resin, which is one of the most recent technologies being applied successfully in the field, (3) polymer solutions, and (4) polymer gel, which is a semisolid material that has shown potential in conformance control applications. This work addresses injectivity and the parameters that affect the injectivity of these materials, which to the authors' best knowledge have not been addressed comprehensively in the literature. The results of this study demonstrate the effects of several factors on the injectivity of the sealants: void size, viscosity of the sealant, injection flow rate, and heterogeneity of the void. The results also promote the use of solids-free sealants, such as epoxy resin, in wellbore remedial operations because epoxy resin behaved like Newtonian fluid and can therefore be injected into very small voids with a minimum pressure requirement.

Using Computer Simulations to Aid the Analysis of Fluid Contaminations During Cement Plug Placement

Setting a cement plug on the target zone either creates a solid seal to stop fluid movement or provides a kick-off point for sidetrack drilling operations. Successfully placing cement plugs is one of most critical steps to ensure trouble free completion, reduce the risk of loss of circulation, isolate pressure zones and enhance wellbore integrity. The traditional method is to pump all the fluids until each fluid level is equal to that inside the string. The limitation to this method is that the fluid could be contaminated once the string is pulled out of the hole, due to variable fluid densities, as well as wellbore and work string sizes. Thus, the volume of spacers pumped ahead and behind the cement and the volume of displacement are critical to the quality of the cement plug. A computer program is developed to model the displacement hydraulics of fluids and simulate fluids contamination during pulling pipe out of hole. The computer modeling aids in optimizing the pumping schedule to ensure balanced slurry and spacer levels after POOH (Pull out of the hole), minimizing contamination within the cement slurry and spacer, ultimately, reducing the risk of loss of circulation and enhancing wellbore integrity.

Algorithms and Models for Smart Well Planning With Emphasis on Trajectory Optimization

Well planning is a time-demanding procedure, which integrates knowledge and experience of various field professionals, as drilling engineers, pipe manufacturers, drilling mud specialists, geologists, etc. According to OG21 report (1), time spent for planning a well is on average 2–3 months. Drilling engineers have to design a well at minimum costs maintaining wellbore integrity at any time. The wellbore should also allow for maximum production from the reservoir and minimum tortuosity for successful casing running and completion. Fortunately, in the well-explored geological areas, where stratigraphic sequences and corresponding geopressures are known, the main objective can be narrowed down to optimal trajectory design. Optimal wellbore trajectory considers at least three criteria: shortest possible path, collision avoidance and longest possible contact with reservoir. Due to large number of modules involved, well planning requires a holistic approach. At the same time, due to complex interaction between the modules and respective physical models, this task implicates a high level of precision. This paper presents a development of an in-house well planning simulator, which integrates all essential well planning modules in a smart way. Central part of the simulator is represented by a trajectory planning and optimization module, which is based on minimization of wellbore length and dogleg severity. Constraints related to anticollision are also included. Introduction of smart optimization techniques for wellbore trajectory has a real potential of saving time and efforts by providing engineers with multiple options, which satisfy the aforementioned constraints. Our ultimate goal is to automate wellbore planning to the largest possible extent by developing smart optimizers for other vital modules within the well planning simulator.

Phase Equilibria of Acid-Gas Aqueous Systems (CO2, H2S, CH4, Water) and In-Situ pH Measurements in Application to Top-of-Line Corrosion

Summary We present thermodynamic modeling and pH measurements of fluid systems containing acid-gases (e.g., CO2 and H2S), water, and hydrocarbons—replicating the production and shutdown conditions in sour fields—for the purpose of evaluating top-of-line corrosion (TLC) and wellbore integrity and screening/selection of the proper wellbore materials. In particular: An equation of state (EOS) model using Peng-Robinson EOS in combination with the Huron-Vidal (HV) mixing rule for an aqueous subsystem is developed. In the model, subject EOS parameters are calibrated against existing thermodynamic data (saturation data for pure components and solubility data for binary systems) in literature. New in-situ pH measurement data are presented for a model system corresponding to a sour field. It was found that the wellbore can be subjected to pH levels as low as 2.7 with reservoir fluid containing 12 mol% CO2 and 88 mol% CH4 with downhole flowing conditions of 200 bar and 150°C and wellhead shut-in conditions of 300 bar and 4°C, as observed from the experiments. A modeling workflow is developed to estimate pH of the condensed water as a function of temperature and composition of the aqueous phase. The comparison between prediction and experimental measurement shows a very good match between the two (within pH ±0.1). Such studies (pH measurements and prediction) are not available in the literature but play important roles in material screening and assuring wellbore integrity for sour fields. More importantly, sensitivity analysis can be performed to investigate the effects of various factors (such as reservoir temperature/pressure, shutdown conditions, and compositions or extent of souring) on pH prediction. Furthermore, the methodologies developed through this work can also be extended to reservoir facilities, pipelines, sour gas disposal/handling units, and downstream systems such as water utilities, reactor plants, and refineries. The work can also support regulation/licensing for these sour systems.

Testing Low-Melting-Point Alloy Plug in Model Brine-Filled Wells

Summary Low-melting-point bismuth- (Bi-) based alloys have recently been proposed for plug-and-abandonment (P&A). Previous experiments have shown the feasibility of BiSn [58-wt% Bi and 42-wt% tin (Sn)] and BiAg [97.5-wt% Bi and 2.5-wt% silver (Ag)] alloy plugs in moderate temperature wells, both across shales and across the shale/sandstone sequence. These were validated in linear and cylindrical wellbore cavity geometries for various differential setting pressures for alloy over air. Until now, all of the experiments for setting alloy plugs have been conducted with air as the wetting fluid. Given the lack of adhesion between minerals and alloy, our concept for providing bond strength and integrity has hinged on providing a bicontinuous structure through alloy penetration into the pore network. For shales, with a positive setting pressure, anchors on the surface, in lieu of pores, have proven to be adequate. With results obtained under excess alloy pressure, we have quantified the effect of setting pressure on the alloy/shale bond quality. With brine as the wetting fluid, imposing an excess pressure on the alloy has not been demonstrated previously. This paper is the continuation of our previously published papers (Zhang et al. 2020a, 2020b), and our objective here is not only to show the possibility of forming a plug under brine but also to quantify the plug’s quality with and without an excess alloy pressure. We first describe an apparatus that controls alloy and brine pressures independently through a semipermeable piston assembly and demonstrate forming alloy plugs in a brine-filled borehole cavity. Based on pressure decay tests across the plug, we demonstrate that wellbore integrity is possible only with a positive alloy pressure over that of brine.