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Conventional well plug and abandonment (P&A) can sever and remove the tubing to access casing or leave it in situ when it does not interfere with providing a seal over an indefinite time frame. This paper assesses the viability of pushing rather than pulling severed production tubing to gain casing access. The P&A decision to push, pull, or leave the tubing in situ depends on confirming existing seals and then placing suitable sealants, such as cement, to keep the risks of future well leakages as low as reasonably practicable (ALARP). Pushing or compacting tubing into the liquid space of a well could be used with smaller rigless units, which cannot hoist the production tubing, but can use production intervention or decommissioning logistics with coiled tubing or wireline cutting and severance. Associated pumps could then drive an inflatable piston to compact split and severed tubing into a lower liquid space to access casing for logging and P&A plugging. Rigless tools and methods have provided dramatic cost savings where casing access was not needed, and thus the present study investigates the viability of accessing casing by means of pushing or compacting tubing to extend rigless P&A use and savings. The viability of pushing and compacting North Sea sizes and grades were confirmed in real-scale physical-compaction simulations of production-tubing joints pulled from offshore wells. Independent small-scale physical simulations and numerical modeling then confirmed that the real-scale results were predictable and repeatable to demonstrate an ability to design and provide a window or gap in a production-tubing string for use by other P&A methods.
However, other technologies can often be employed to investigate properties of the earth that correlate better with the properties of interest. If the images from these technologies can be provided at appropriate resolution, and if the knowledge required for interpretation and wise application of these technologies is available within the industry, they should be used. For example, electrical methods are extremely sensitive to variations in saturation, yet surface-based methods provide very poor resolution. Reservoir compaction can be directly observed from surface deformation, and pore-volume or gas-saturation changes can be detected from changes in the gravitational field. Dramatic examples of surface deformation induced by reservoir compaction have been provided by releveling studies (involving repeated high-accuracy surveying) and satellite-based interferometry.
One of the PDO’s largest producing field with vertically stacked carbonate reservoirs gas from shallower Natih Formation, and produces oil from lower Shuaiba formation with waterflood recovery. Natih formation is a highly compacting formation characterized using rock mechanics laboratory measurements. Currently there are more than 500 Shuiaba wells that are active, which penetrate through the highly compacting Natih Layer above. Reservoir compaction of Natih A has induced damage to several wells most likely due to compression and buckling of the casing within the production interval. The field has obeservations to well integrity and impact to production performation related to the casing deformation resulting from the compaction.
The well Integrity issues for Shuaiba wells are being resolved with work over operations, repairs. In few severe cases, it was required to abandon the well. All of these issues impact operational expenditure and production (loss and/or deferment). Risk assessment for wells with future depletion (or time) can provide input to manage the risk, plan adequate mitigations and capture the impact in the future drilling campaigns for well stock. To do so it was important to identify and quantify well counts, which have high potential to have well integrity issues or risk of failure
In the studied field, subsurface compaction is being monitored/measured since 2000, using Compaction Monitoring Instrument (CMI) that measures compaction between preplaced radioactive markers in the formation and the casing in five CMI monitoring wells. Data of CMI compaction log, historical well failures, spatial well locations, rock mechanics measurements was integrated to quantify risk of expected well failures in future. The results from the CMI logging showed that the compation in the entire reservoir interval is not uniform and upper layers in the reservoir intervals were subjected to very high compaction strains compared to lower layers. The Uniaxial Pore Volume Compressibility (UPVC)) coupled with analysis of CMI data provides a forecast for maximum compaction strain in the upper reservoir layers up to 5 % at abandonment pressure.
The analysis of reported/observed well failures reveals that approximately 77% of the impacted wells were during 1971-2000. Using these inputs a risk assessment matrix for well failures was developed, which provided potential wells with high risk of failure/well integrity issues, which accounted to about 34% (~ 85 wells) of the active wells. Results of this study provided input to capture in the development plans and build adequate mitigations to help minimize production loss/deferment
Sajjad, Farasdaq (PT Pertamina Hulu Energi Offshore Northwest Java) | Chandra, Steven (Institut Teknologi Bandung) | Naja, Savinatun (PT Pertamina Hulu Energi Offshore Northwest Java) | Suganda, Wingky (PT Pertamina Hulu Energi Offshore Northwest Java)
We present a simple analytical solution to diagnose gas production under compaction. This solution scales production profile of different wells and collapses them into a single general curve. The curve will later serve as the "learning" function for physic-based machine-learning prediction.
A rapid growing flood of big data in the oil and gas industry reveals a substantial opportunity to the better understanding of hydrocarbon reservoir. With machine learning, one can turn a numerous amount of data to predict future production and determine field economics. However, the quality of the prediction from machine learning is dependent on the learning function selected that most of the time does not concatenate any physical aspects of the problem. In this paper, we offer a better machine learning with a physics-based function to estimate future gas production under severe compaction.
We construct a physic-based master curve by solving the coupled Darcy-Biot equation for vertical gas well under reservoir compaction. We assume that the flow is radial and the porosity is transiently changing by the reduction in pore pressure due to gas production. Finally, we reduce the complexity of the coupled non-linear equation to two scaling optimization parameters: a mass scaling factor to scale the recovery factor and time scaling factor to scale the diffusion time.
We verify our model with a field case from KLX field, Indonesia. This gas field produces an enormous amount of gas with subsidence as the side effect. The subsidence was identified by knowing the change in platforms level. By collapsing the production profile of all existing wells into a single master curve, we capture the universal scaling parameters that represent the behavior of gas flow under reservoir compaction. Furthermore, we can substitute the resulted master curve as the learning function for to the machine-learning model to predict and diagnose other fields in the future that undergo the same phenomena.
We find that reservoir compaction leads to a higher recovery factor of gas for a long term. However, the high subsidence rate is not a favorable condition for the offshore field as the production facilities on the platform will submerge under sea level in a matter of years. Thus, the field owners must consider some subsidence mitigations such as injection and maintaining critical production rate.
Our novelty is to produce a general scaling to describe gas production under compaction, which is later useful for the development of our machine-learning process to simplify the prediction process, not involving extensive and expensive numerical simulation.
Sajjad, Farasdaq Muchibus (PT Pertamina Hulu Energi Offshore North West Java) | Hadi Prasetyo, Abraham (PT Pertamina Hulu Energi Offshore North West Java) | Chandra, Steven (Institut Teknologi Bandung) | Wijaya, Budi Rivai (PT Pertamina Hulu Energi Offshore North West Java) | Naja, Savinatun (PT Pertamina Hulu Energi Offshore North West Java)
Abandonment and site restoration (ASR) is one of the responsibilities of Oil and Gas Company for the country where it operates. The ASR covers plug and abandon (P&A) of wells and dismantling of surface equipment in order to restore the environment as close as possible to its original state. Current practices in Indonesia's oil and gas business does not put P&A as one of the top priorities, compared to other engineering aspects in petroleum engineering. Therefore, P&A is sometimes regarded as a formality. A case study where long term oil and gas exploration and production with unique rock mechanics in Offshore North West Java (ONWJ) Area has caused subsidence and inherently leading to both production operation and well integrity issues. Several issues namely casing deformation and detachment from main casing strings have been observed and is likely to put harm to oil and gas production in ONWJ Area. Casing issues such as buckling and crumpling, as well as the presence of micro cracks will present complications in safely plugging and abandoning the affected wells. Recommendations based on current practices around the world as well as mitigation solutions done in ONWJ Area such as mechanical stress and/or strain release combined with well condition evaluation and monitoring is maximized as an input to properly design safe and cost efficient P&A strategy for complex, marginal, and offshore wells with integrity issues. This research is aimed to become a benchmark for future uses of P&A not only in ONWJ area but also in Indonesia.
Summary Numerical and analytical 1D solutions are presented to interpret the link between geochemical alterations and creep compaction (compaction under constant effective stress) in chalk cores. An explicit analytical solution is derived for the steady-state ion and dissolution-rate distributions at a given injected composition and injection rate. Brine-dependent and nonuniform compaction is hence built into the model by means of the dissolutionrate distribution. The model is validated and parameterized against data from a total of 22 core samples from two chalk types (Åalborg and Liege) where reactive and inert brines were injected from ambient to Ekofisk-reservoir conditions (130 C). Experimentally measured effluent concentrations, distributions in mineralogy after flooding, and creep-compaction behavior were matched. Our model is the first to link a vast set of data on this subject and predict performance under new experimental conditions. Brines injected through Liege chalk appeared to approach stable oversaturation, while in Åalborg, the equilibrium condition was in agreement with geochemical calculations. Introduction Chemically reactive flow is a key phenomenon in underground storage and transport. For the petroleum industry, relevant processes range from fines migration, precipitation and scaling events, carbon capture and storage, wettability alteration, geological development of sedimentary structures, and weakening of load-bearing formations (Shinn and Robbin 1983; Kharaka et al. 2006; Austad et al. 2008). Seawater injection for pressure-driven oil recovery, especially in chalk formations, has displayed a strong reactive interaction, with implications for wettability and compaction. Chalks are characterized not only by high porosity (40 to 50%) and permeability in the md range but also by high reactivity because of a high specific surface area of 2 to5m 2 /g (Hjuler 2007; Andersen et al. 2018). Water injection was performed, but the compaction continued even after pressure stabilization (Sylte et al. 1999). Research on a core scale has demonstrated that chalk is weakened by the reactive interaction with seawater. In particular, the seawater ions Mg 2þ,SO 2 4, and Ca 2þ interact with the rock in a complex interplay and lead to the dissolution of the calcite mineral CaCO 3 (Madland et al. 2011), the main constituent in the chalk matrix. A high EOR potential by brine-dependent spontaneous imbibition has been demonstrated for chalks by varying the ions naturally appearing in seawater (Hirasaki and Zhang 2004; Zhang et al. 2007). This often involves loading chalk cores beyond their yield point in triaxial cells and leaving them at constant-effective-stress conditions, while they compact with time [creep compaction (Fjær et al. 1992)].
ABSTRACT: Reservoir sands experience pressure depletion from the production of fluids that are contained within them. These producing sands can be so depleted that they hinder future developments of deeper producible sands because of the corresponding reduction in stresses across such depleted sands that may present mud weight constraints for in-fill drills. Our experience in fields in the Gulf of Mexico has shown that issues related to depleted drilling (such as lost circulation) typically occur in the shales above or below depleted unconsolidated sands. In this paper, evidence is provided to show that the pressure in shales can reduce and can be a contributing mechanism to the issues encountered in these shales. For this study, a 1-D pressure diffusion model was utilized to simulate pressure changes in bounding shales of multiple depleting reservoirs in a field in the Gulf of Mexico. The modeled shale pressure depletion was then converted to strain using assumptions on compressibility. The strain estimates were subsequently compared with the strain measurements data acquired from Formation Compaction Monitoring logging across various sands in several wells in the field. The study shows that the strain associated with pressure depletion can account for the strain experienced in these bounding shales, and thus provides a means to explain the stress reduction associated with the shales and the associated lost circulation events. This will enable better informed decisions in designing wells and can save millions of dollars in cost due to downtime from lost circulation and borehole instability during drilling through depleted zones.
The extraction of fluids from oil and gas reservoirs causes a reduction in their pore pressure, and for porous media such as sandstones, this results in poro-elastic deformation (or compaction) of the reservoir, and subsequent reduction in horizontal stresses. Both effects can have serious implications for oil and gas installations and operations. The process of compaction, for example, increases the risk of wellbore failure, sand production, and also surface subsidence amongst others; while a reduction in horizontal stresses in the reservoir can create issues with drilling margins and thus impede further development of a hydrocarbon field. The materialization of any of these risks can have significant cost impact on projects and companies.
ABSTRACT: Creep is an inelastic mechanism with severe implications on the long-term mechanics of fluid-bearing reservoirs and underground geophysical systems. In the context of porous rocks, recent experimental studies have shown that such class of geomaterials may exhibit delayed inelasticity if deformed in the compaction banding regime. In such circumstances, compaction banding results from the interaction between the rock heterogeneity and the temporal evolution of its mechanical properties. In this paper numerical analyses based on the Finite Element method are conducted to investigate the influence of the spatial heterogeneity of the material on the onset and development of localized compaction creep. For this purpose, an elastoplastic constitutive law able to replicate strain localization has been adapted to a rate-dependent formalism, thus enabling the simulation of creep. Numerical analyses of triaxial compression tests have then been conducted by varying the statistical attributes of the rock heterogeneity. The simulations revealed that spatial variations of yielding resistance provide a hotspot for viscoplastic strain, eventually affecting the spatiotemporal patterns of propagating compaction zones. Most notably, it was found that relatively small fluctuations from the average rock properties may generate non-negligible delayed compaction, as well as strain localization. These results emphasize the importance of the natural heterogeneity in the simulation of compaction, especially in case of highly porous reservoir rocks.
The long-term stability of subsurface rock formations is a concern for reservoir engineering because of its role in a variety of applications, such as hydrocarbon extraction (Sternlof et al., 2006) and underground CO2 sequestration (Torabi et al., 2015, Rass et al., 2017). In this context, reservoir compaction can have significant consequences on extraction/injection activities (Torabi et al., 2015, Rass et al., 2017) and may become a source of land subsidence (Nagel, 2001) and seismicity (Cruz, 2018). Porous rocks undergo compaction as a result of the alterations in the stresses resulting from the depletion/injection of pore-fluids, which may lead to permanent damage at the micro-structural level. While compaction has been frequently reported during extraction, many incidents have documented their occurrence long after the termination of the operations (Hettema et al., 2002). Compaction under constant boundary conditions reflects the inherently time-dependent deformation of rocks, which according to recent evidence can even take place in localized form if the material is highly porous (Heap et al. 2015). In such cases, distinct deformation patterns can be observed, with samples exhibiting alternating stages of acceleration and deceleration. This phenomenology stems from heterogeneous microscopic alterations such as cement debonding, inter-granular slippage, and grain crushing (Wong and Baud, 2012), through which the tendency to deform under constant loads can be regarded as an outcome of subcritical fracture growth and distributed micro-cracking. In fact, the heterogeneity of porous rocks is inherently a multi-scale property that spans from the pore-scale up to the field scale. While fracture mechanics can explain the role of microstructural heterogeneities on the time-dependent behavior of the material, the role of the mesoscale heterogeneities at the scale of rock core is still under-explored, as is readily apparent from the not yet fully understood role of spatial fluctuations of material properties on the triggering of strain localization (Borja et al., 2013, Shahin et al., 2016). This paper is motivated by these considerations and aims to explore the link between rock heterogeneity and localized compaction creep from a numerical standpoint.
ABSTRACT: Extensive exploitation of water resources and fossil fuels is known to lead to long-term, spatially distributed land subsidence. The resulting ground settlement can be a major cause of infrastructure damage and economic loss, especially in coastal areas where subsidence contributes to increased risk of flooding and ecosystem deterioration. Although from a geomechanical standpoint, rock compaction due to pore pressure decrease is the major driver of ground settlement, the spatiotemporal distribution of subsidence is affected by a number of factors, such as site heterogeneity, variability of reservoir geometry, porosity fluctuations, and local differences in depletion history at extraction wells. To account for these factors while maintaining reasonable adherence with the physics of the problem, this paper aims to incorporate simple poroelastic solutions of land subsidence into a regional model accounting for spatial variations of the controlling parameters. For this purpose, the classical Geertsma solution is used to replicate the subsidence induced around a well, while pore pressure diffusion analyses are employed to simulate the delay between depletion history and ground settlement. Superposition principles are then used to assess the interaction between neighboring wells, eventually obtaining a spatiotemporal map of the expected subsidence. The methodology is finally tested for simplified arrangements of extraction wells, as well as under coupled and uncoupled scenarios. The results demonstrate that hydro-mechanical couplings may lead to non-negligible nonlinear subsidence trends even in the presence of linear poromechanical properties, thus making spatially distributed models a useful resource for a first-order assessment of the progression of ground settlements across a large region.
Land subsidence is a critical source of hazards in coastal areas around the world (Eggleston and Pope, 2013). Its spatial extent and temporal progression can cause damage to infrastructure (Dixon et al., 2006) and/or ecosystem deterioration over the span of several years. A well-known example is Jakarta, a coastal megacity that is sinking at an average rate of 8 cm/year, with some zones experiencing rates as high as 22 cm/year (Chaussard et al., 2013), drawing extensive coverage from the international press (Kimmelman, 2017).
ABSTRACT: Recognizing and quantifying geomechanical risk is often impaired by a lack of input data. To assist the assessment of depletion-induced reservoir compaction of sandstones, we developed a new set of correlations that fully respect the operative microphysical mechanisms. We re-analyzed triaxial compressive strength and uniaxial-strain compressibility data for sandstones from fields located in progressively buried basins and subjected to normal faulting stress conditions. New correlations are: a) a linear relationship between Apparent Cohesion the field's Virgin Vertical Effective Stress, b) an exponential relationship between the uniaxial-strain compressibility Cm and the Apparent Cohesion, and c) a polynomial relationship between the horizontal depletion path constant γh and the Apparent Cohesion. The correlations reveal two distinct types of constitutive behavior, namely ‘non-cohesive’ and ‘cohesive’ domains separated around an Apparent Cohesion of 8 MPa. This separation occurs at a depth of approximately 1 km, or deeper when the formation is subjected to significant overpressure. The global correlations described here offer a means to estimate the general compaction response of sandstone at conditions relevant to pressure depletion, provided that the sandstone is situated in a progressively-buried basin, in a normal faulting setting.
Compaction and subsidence risk is among the most significant geomechanical risks known to the industry. Subsequent effects in the Wells, Reservoir and Facilities Management (WRFM) space include shearing of wells, subsurface deformation extending to induced seismicity, and catastrophic damage or instability of platforms. Recognizing and quantifying such effects is initiated in an early stage of any petroleum development project (that is deemed sensitive to this risk) and requires information about the initial 3D stress state and expected pore pressure change, as well as the rock compressibility or compaction coefficient. Screening activities commonly rely on analogue data, correlations, and/or practical experience that is often poorly constrained by physical understanding of rock deformation processes. As a result, the independent quality control of the model predictions can be problematic. To assist the assessment of depletion-induced reservoir compaction of sandstones, we re-analyzed sandstone mechanical data from (anonymized) fields located in progressively buried basins and subjected to normal faulting stress conditions.