Estimation of cement thermal properties through the three-phase model with application to geothermal wells

Geothermal energy has been used by mankind since ancient times. Given the limited geographical distribution of the most favorable resources, exploration efforts have more recently focused on unconventional geothermal systems targeting greater depths to reach sufficient temperatures. In these systems, geothermal well performance relies on efficient heat transfer between the working fluid, which is pumped from surface, and the underground rock. Most of the wells designed for such environments require that the casing strings used throughout the well construction process be cemented in place. The overall heat transfer around the wellbore may be optimized through accurate selection of cement recipes. This paper presents the application of a three-phase analytical model to estimate the cement thermal properties. The results show that cement recipes can be designed to enhance or minimize heat transfer around wellbore, extending the application of geothermal exploitation

Liquid loading in gas wells: From core-scale transient measurements to coupled field-scale simulations

Liquid loading is a major operational constraint in mature gas fields around the world. It manifests itself as an increasing back pressure on the reservoir due to a rising liquid column in the well, which initially decreases deliverability, then ultimately causes the gas well to cease production. Theoretically, every gas well will experience this debilitating phenomenon in the latter stages of its producing life. In this paper, both laboratory experiments and numerical simulations are presented to shed more light on the physical process of liquid loading, with a focus on reservoir responses. On the one hand, core-flooding experimental setups of different scales were designed and constructed to investigate back pressure effects on transient flow through the near-wellbore region of the reservoir. On the other hand, the modelling of a gas well undergoing controlled flow and shut-in cycles was performed to validate core-scale observations at reservoir scale, using commercial integrated numerical software that connects a transient wellbore model to a transient reservoir model. The simulated transient characteristics of short-term downhole dynamics (e.g. liquid re-injection and co-current/counter-current flows) supported the U-shaped concept observed in the experiments. The detected temporal distribution of pore fluid pressure within the reservoir medium itself (referred to as the U-shaped pressure profile) was observed both experimentally at the core-scale and numerically at the reservoir-scale. This pressure distribution can be used to explain re-injection of the denser phases into the near-wellbore region of the reservoir

Estimation of plugging and abandonment costs based on different EU regulations with application to geothermal wells

This paper presents the cost of plugging and abandonment (P&A) of the Horstberg Z1 well and shows how the well history is considered in the P&A planning process together with existing European regulations. Three different design plans are presented, based on innovative ideas and best practices in the oil and gas industry. Horstberg Z1, located in Germany, was originally a gas well, converted to a scientific geothermal well to prove the single well concept. After serving as a geothermal well for several years, the well has been proposed for P&A. The three designs presented in this work fulfill the purposes of well P&A, and meet the BVOT requirements, which are standard requirements for wells in Lower Saxony, Germany. Following a financial analysis of the designs, it is noted that rig costs are the largest element of the total expenditure, contributing over 50% in the design plans considered. As the number of cement plugs and round trips increase per design plan, the implementation period also increases, which impacts on the total cost. Based on the investigations made in this project, a minimum of USD 1,275,500 is required for the plug and abandonment cost of the well, excluding the well site re-cultivation. A rigless solution for pulling heavy casing out of the wellbore, to avoid the use of a conventional workover rig, would significantly reduce the plug and abandonment cost of the Horstberg Z1 well

Quantifying the Effect of De-Emulsifiers on Acid Treatment in Carbonate Formations

Matrix acidizing is a highly successful, effective, and relatively inexpensive approach to enhancing well productivity in carbonate formations. Accordingly, there has been little motivation to address the ways to optimize the acid stimulation process better. Acid-in-oil emulsions that form during this process cause one of the most challenging problems that negatively impact the performance and deliverability, especially when these emulsions are highly stable over extended periods. Such stable emulsions can plug the flow path of oil causing high resistance to flow and potentially reducing well productivity. De-emulsifiers are some of the most widely used acid additives targeting the reduction of emulsion stability. However, there is doubt in the research community on whether there is enough shear mixing that can cause the formation of emulsions inside the rock matrix. Besides, the effectiveness of de-emulsifiers in eliminating such emulsions in the pore space has not been investigated. In the current oil price market, there is a need to be more vigilant regarding the cost of well stimulation and the added value from the various additives. While laboratory work on matrix acidizing in carbonate formations is abundant, the work on oil-saturated samples is rare, and therefore, the effect of emulsions on the acidizing process has not been widely documented. In this work, we present a stacked study of bottle tests and core flooding tests designed to investigate the de-emulsifiers’ role in the rock matrix. The results reveal that (1) emulsion-risk in the pore space is real, and (2) the addition of de-emulsifiers to the acid allows for efficient backflow of oil, revealing an improvement in the performance of the acidizing treatment.Ye

Assessment of deep geothermal energy exploitation methods: The need for novel single-well solutions

Geothermal energy is a constant and independent form of renewable energy and plays a key role towards the world's future energy balance. In particular, deep geothermal resources are largely available across continents and can help countries become less dependent on energy imports and build a broader base in their future energy mix. However, despite its significant potential, the total contribution of the geothermal sector to global power generation remains relatively small. The International Energy Agency has recommended devising plans to address technology-specific challenges to achieve faster growth and improving policies tackling pre-development risks for geothermal energy. Reaching considerable depths is a requirement to exploit deep geothermal resources, but experience gained to date from the implementation of complex, engineered deep geothermal projects has unveiled technical and economic challenges, lower-than-expected performance and poor public image. There is therefore an urgent need for alternative, more sustainable well designs. This paper critically assesses conventional and unconventional deep geothermal well concepts, focusing on the basic Borehole Heat Exchanger (BHE) concept. The discussions are supported by numerical simulations of a BHE design that includes heat conductive fillers to enhance the heat exchange with the surrounding formation, while avoiding direct fluid interaction with the latter

Analytical and Experimental Investigation of the Critical Length in Casing–Liner Overlap

Offshore drilling operations exhibit various difficulties attributed to shallow flows worldwide. One of the most common practices for drilling offshore wells is to use liners and liner hangers rather than using full casing strings. This reduces the cost of drilling operation. Liners and liner hangers are required to pass certain standards prior to their deployment in the field. This ensures their ability to withstand harsh downhole conditions and maintain the integrity of the well. A liner hanger contains an integrated seal assembly that acts as a barrier to prevent fluid migration. The cement that is placed within the casing–liner overlap is also considered a barrier, and it is critical that it maintains the integrity of the well by mitigating fluid migration to other formations and to the surface. The failure of this dual barrier (cement and seal assembly) system to seal the annular space can result in serious problems that might jeopardize a well’s integrity. Typically, in field applications, the length of a casing–liner overlap is chosen arbitrarily. In some cases, shorter overlaps (50 to 200 ft) are chosen because of the lower cost and easy identification of leaks during pressure tests. However, some loss of well control incidents (particularly the incident that motivated this study) have been linked to fluid leakages along the casing–liner overlap. This paper investigates the critical length of the casing–liner overlap by modeling gas leakage through the cement placed within the overlap using analytical and experimental approaches. Leakage scenarios were developed to mimic gas migration within the cement in the casing–liner overlap. The results showed that the longer the casing–liner overlap, the higher the leakage time. The results also showed that the current casing pressure test duration of 30 min may not be adequate to verify the integrity of the cement within the overlap. Based on the results and analyses, it is recommended to increase the pressure test duration to 90 min. In addition, the results suggest that the length of the casing–liner overlap should not be less than 300 ft to maintain the integrity of the well in the case of gas influx. Further details are highlighted in the results section. In practice, the current rationale behind the selection of a casing–liner overlap length is not sustainable. Thus, the major advantage of this study is that with field data, it provides both scientific and research-based evidence that can be used to inform the decision behind the selection of the casing–liner overlap length, especially in gas migration-prone zones.This research was funded by the Bureau of Safety and Environmental Enforcement (BSEE), Project number E17PC00005. Open Access fees paid for in whole or in part by the University of Oklahoma Libraries.Ye

A Review of Recent Research on Contamination of Oil Well Cement with Oil-based Drilling Fluid and the Need of New and Accurate Correlations

Drilling fluids and oil well cement are important well barriers. Their compatibility affects the long-term integrity of the well. The mixing of drilling fluid with the oil well cement causes contamination of oil well cement. If the contamination is due to diesel/oil-based drilling fluid (OBF) it adversely affects the rheological and mechanical properties of oil well cement—in other words, the long-term integrity of the well. An initial study on OBF contamination of oil well cement was carried out two decades ago. In recent years, several research projects were carried out on the same topic to understand the reason for changes in the properties of oil well cement with OBF contamination. This literature review shows that using OBF eliminates several drilling problems, as the long-term integrity of the well depends on the amount of OBF contamination in the cement slurry. This paper compares the experiments performed, results and conclusions drawn from selected research studies on OBF contamination of oil well cement. Their shortcomings and a way forward are discussed in detail. A critical review of these research studies highlights the need for new and accurate correlations for OBF-contaminated oil well cement to predict the long-term integrity of wells

Comparing completion design in hydrocarbon and geothermal wells: The need to evaluate the integrity of casing connections subject to thermal stresses

Tapping for geothermal energy very often requires deep drilling in order to access high-temperature resources. This type of drilling is expensive and is financed by the operator with a long period of debt service before costs can be recovered from the energy sale (heat, electricity or a combination of both). Drilling costs are only a part of the total well expenditure. Tubulars can double the total well cost, especially when complex well completions are required. Together, drilling and well completions can account for more than half of the capital cost for a geothermal power project. A comparison is made of the different completions used for oil, gas and geothermal wells, and geothermal well completion requirements are discussed. Special attention is given to the thermal stresses induced by temperature variations in the casing string of a geothermal well. When the induced thermal stresses exceed the yield strength of the casing material, the fatigue behavior of the latter can be defined as low-cycle fatigue (LCF). The connection threads in the casing body amplify the local stresses and lower the LCF resistance. A theoretical approach is presented to evaluate that parameter, and calculations are compared with preliminary results from experiments on large-diameter Buttress connections, which are commonly used in geothermal well completions. It is shown that under extreme loads the LCF resistance of the Buttress thread connection can be as low as 10 cycles