Irreducable casing pressure, also known as Sustained Casing Pressure (SCP), cannot be bled off permanently as it is caused by annular gas migration from the leaking cement. SCP poses environmental risk, and regulations demand its removal - particularly prior to well's plugging and abandonment operation. Bleed-and-Lube method, which is cheaper than the conventional mechanical removal methods, involves injecting heavy fluid into the affected annulus that would displace the annular fluid, balance the pressure at the top of cement and stop the gas leakage. Previous studies stated that the use of immiscible combinations of two fluids is more effective for the purpose; however, inattentive applications may result in excessive use of heavy fluid. In this study, a 20-foot carbon-steel pilot well annulus was manufactured and used for displacement experiments with various drilling muds and heavy fluids with different characters. Pressure change data was collected from four different levels of the annulus and volumes of fluids going in and out of the annulus were measured. Experiments indicated the formation of a mixture zone that would build bottoms up and expand during ongoing displacement. Proposed pressure build-up model suggests an exponential distribution of density of this zone, and shows its high depencency on fluids' properties and injection rate. The models were also converted into dimensionless process measures and proposed for the use in real well applications. The study clearly demonstrates the viability and recommends the correct application of the method.
We conducted a theoretical study to investigate the techniques for developing a geologically complex turbidite reservoir in highly constrained oil field underlying a city. Not only does the geology present significant challenge in terms of heterogeneity and anisotropy, the surface constraints make it very difficult to plan the development of wells because of health, safety, and environment (HSE) issues.
With a strong economic focus, the study incorporated various sensitivities and uncertainties in CAPEX and OPEX in establishing novel ways of optimizing infill well locations, drilling in an urban area, and enhancing hydrocarbon production through reservoir simulation practices. For reservoir simulation, well logs, production history, and laboratory data were taken from an analogous field. This, plus the presence of certain unique events in the history of some of the wells, imposed limits on the study.
The methodology of the dynamic modelling is unconventional in terms of analyzing the field for forecasting right after initialization, followed by a detailed history match considering the numerous complexities of a turbidite environment. This allows greater time for field development planning, which is typically given the least attention in modelling because of time constraints. The prediction comprises three cases—a no-further-action case, an infill drilling case, and a waterflood scenario. A combination of vertical and horizontal well trajectories was used to achieve the best output across a range of economic sensitivities over multiple scenarios. The study covered a broad range of realizations of well trajectories, well placement, optimized drilling, and production services, such as is done in a constrained urban environment like Los Angeles, California. Our modelled city was Houston, Texas, a well-known urban environment. As a result of the modelling, a technique was developed to account for environmentally safe development within this example.
The technological and economic conclusions make this a foundation study for profitable development of reservoirs underneath a populated area. The study may also be instrumental in exploitation of turbidite reservoirs, which present challenges in current North Sea and Brazil offshore development and in recently discovered submarine fans in the Gulf of Mexico deep marine environment.
Tasbulat field was one of the fields discovered during Soviet times in the 1960’s by the regional exploration drilling campaign in the South Mangyshlak basin. It consists of multiple stacked oil and gas reservoirs of lower to mid Jurassic and mid Triassic age. The main reservoir in terms of oil production, initial oil in place, reserves and development progress is the Jurassic 10b which is an anticline shaped tidal-fluvial channel which is filled with under saturated oil. The lateral extension of the productive Jurassic 10b reservoir has been defined by a number of wells. Moreover, towards both flanks of the field the oil-water contact has been penetrated. Production from the Jurassic 10b reservoir commenced in the 1970’s under natural depletion. Water injection was started in 2003 and gradually increased in terms of volume and number of injection wells.
Breakthrough of injection and/or aquifer water has been observed in parts of the field. At present, the Jurassic 10b is being developed with 13 oil producers and 7 water injectors. A large portion of the producers have been hydraulically fractured which adds another layer of complexity. A recent multidisciplinary approach has significantly improved understanding of the Jurassic 10b by integrating static and dynamic data sets. The approach entailed a systematic review and interpretation of production, injection and well history based on which the lateral extension of the water flood front was estimated and drawn. The position of the flood front was subsequently confirmed and refined using dynamic reservoir simulation.
At the same time, sedimentological core description identified a number of lithofacies which identified the Jurassic 10b as a fluvial-tidal dominated system. Based on this knowledge a conceptual sedimentological model for the Jurassic 10b was obtained. In addition, seismic attribute analysis was performed and several channel features were identified and picked. The features were then projected on maps of different reservoir properties (e.g. net sand thickness, pressure, productivity index, water flood front etc.) and it was checked whether correlations existed between features and properties. Using the integrated approach it was shown that the Jurassic 10b channels exhibit hydraulic communication over a significant area, possibly in both, vertical and horizontal direction. And furthermore, that seismic attributes such as similarity and spectrum decomposition could potentially be used for predicting channel extensions.
This paper describes a real example how different methods and techniques such as seismic attribute modelling, lithofacies modelling, production surveillance/engineering, reservoir simulation can be practically used to define a field development strategy.
The paper presents a practical method for calculating the matrix-fracture fluid transfer correctly, applicable under expansion, solution gas, capillary and gravitational drives and their combinations, considering water, gas and oil as displacing agents. The method is an improvement of the Reiss (1973) formulation based on time-depending recovery functions. Reiss could not consider depletion drive in combination with water and gas displacement. Kazemi et al. (1976) extended the Warren-Root shape factor approach to multiphase cases, but without satisfying the conditions under which the single-phase solution is correct. Since that continuous efforts were made for improvement including diversification and making the shape factor time-dependent.
Within the European context, CO2 storage operations shall address the potential impacts of large scale CO2 storage through risk assessment. The key risks identified for this onshore CO2 storage site were the migration through faults and ground deformation.
To quantify the CO2 migration along a fault, flow modelling and uncertainties management codes are coupled to compute the failure probability i.e. the probability of CO2 migration towards a control aquifer. Such probability of failure is characterized by low to very low probability of occurrence which requires a large number of simulations to enable its evaluation. Each failure scenario models the CO2 migration from a storage aquifer to a control aquifer when altering the flow properties of the fault zone. Fault failure analyses are performed on the surrogate models. They show that limited CO2 migration is occurring along the fault but no breakthrough in the control aquifer. The injection induces some pressure disturbance in the control aquifer in about 30% of the cases which lead to effective stress changes.
To quantify effective stress changes due to CO2 injection and the subsequent ground deformation, the mechanical responses of the different sediment layers are modeled coupling flow and geomechanics. The impact of the stress changes on porosity and permeability of the storage reservoir is modeled along with the impact of uncertainties of the mechanical parameters. For this onshore CO2 storage site study case, the expected ground displacement is negligible (below the limit of the measurement capabilities).
Between 2007 and 2014, TAQA Energy converted the Bergermeer field from a depleted gas field into a gas storage with a working volume of 4.1 billion normal cubic meter (BCM) and a production capacity of over 57 million Nm3/day from 14 wells. During this project, with a CAPEX of more than 800 million Euro (excluding cushion gas and transportation commitments), a tight planning schedule was followed. The schedule required full integration of technical, commercial and economic disciplines and had to follow an operational plan to ensure that the project would be realised on time. In order to deliver the entire system, according to technical specifications and commercial requirements, a pragmatic in-house simulator was developed: GRIP (Gas Re-Injection and Production). The tool is based on nodal analysis and uses the key parameters that would determine the performance of the storage elements. After running multiple realisations an optimum design of the gas storage was selected. During the define, execution and operation stages of the Bergermeer storage, GRIP was also used for further optimisation, forecasting and monitoring of the actual performance. The results show that the tool has been very successful in predicting the storage operational envelope, and that integration between disciplines is the key to the success.
We examine the along-hole profiles of oil and water in the highly deviated drain of a light oil carbonate reservoir offshore UK, and analyse the discrepancy between the volumes calculated from LWD resistivity-porosity (Archie) and from magnetic resonance and dielectric dispersion wireline tools conveyed by open hole tractor. We also correlate the petrographic analysis of these bioclastic (ostreiid) grainstones and packstones to the logs responses and rock types.
Following the acquisition of LWD resistivity and porosity logs, additional formation evaluation logs – a combined tool string of NMR, dielectric dispersion, borehole images and formation pressure – was recorded in a single run conveyed by an open hole tractor between the toe and heel of the highly deviated (60-70 deg.) drain.
The water volume profile calculated from resistivity-porosity Archie analysis – the only data type available in earlier wells – is compared to the volumes of capillary bound water from NMR and to the dielectric dispersion water-filled porosity. In a well drilled with oil base mud, we expect that oil filtrate invades the formation, so that the water volume measured by dielectric dispersion represents capillary-bound plus clay-bound water volume and should be equal to the bound fluid volume measured by a NMR tool. Differences between these water volumes represent either formation evaluation anomalies or the presence of free (moveable) water.
Guided by the petrographic analysis of core samples from the same formation and the textural information from the NMR and dielectric dispersion logs, 3 main rock types are identified, to be propagated onto the other field wells with conventional porosity, resistivity, and GR logs.
The evaluation of LWD resistivity-porosity logs provides moderate and almost constant water volumes along the length of the drain, seemingly independent of total porosity variations. In contrast, the water volumes from NMR and dielectric dispersion are more variable, correlating well with total porosity and with the laminated features observed on the borehole images. We also observe that the NMR bound fluid water volume matches the dielectric water volume, and that they are both larger than the resistivity-porosity Archie water volumes.
We propose that the NMR and dielectric water volumes are correct and correspond to variations in reservoir properties in the different rock types, that the more accurate hydrocarbon volume profile is provided by the difference between total porosity and NMR bound fluid volume or dielectric porosity, and that water is at irreducible saturation along the whole drain section.
Although the NMR and dielectric dispersion logs have been used before to resolve carbonate formation evaluation problems, they have rarely been used in highly deviated drains and it is likely that the tractor conveyance and tools combination is unique to this project. Bioclastic (ostreiid) grainstone and packstone reservoirs are also rare, as is the correlation of petrographic analysis to NMR and dielectric dispersion logs in this environment.
A model for real gas transfer in nanopores of shale gas reservoirs (SGRs) was proposed on the basis of the weighted superposition of slip flow and Knudsen diffusion, where the ratios of the intermolecular collisions and the molecule-nanopore wall collisions to the total collisions are the weighted factors of slip flow and Knudsen diffusion, respectively. The present model takes account of slip effect and real gas effect, additionally, the effects of cross-section type and its shape of nanopores on gas transport are also considered in this paper. The present model is successfully validated against existing molecular simulation data collected from different sources in literature. The results show: (1) the present model is reasonable to describe all of the gas transport mechanisms known, including continuum flow, slip flow and transition flow in nanopores of SGRs; (2) cross-section type and shape of nanopores both affect gas transfer capacity: at the same cross-sectional area, gas transfer capacity of nanopores with a circular cross-section is greater than that with a rectangular cross-section, and gas transfer capacity of nanopores with a rectangular cross-section decreases with an increasing aspect ratio; compared to cross-section type, the effect of cross-section shape on gas transfer capacity is stronger; (3) a real gas effect improves gas transfer capacity, which becomes more obvious with an increasing pressure and a decreasing pore size; (4) and compared to nanopores with a circular cross-section, the effect of real gas effect on gas transfer capacity of nanopores with a rectangular cross-section is stronger, and the effect increases with an increasing aspect ratio. The proposed model can provide some theoretical support in numerical simulation of reservoir behavior in SGRs.
Acid fracturing is one of the methods for well stimulation in carbonate formations. Compared to propped hydraulic fracturing, acid fracturing takes a simpler procedure, and therefore, usually with a lower cost. On the other hand, fracture conductivity is more difficult to maintain, especially in formations that have high closure stress. In this study, a procedure is developed to evaluate the feasibility of acid fracturing by comparing conductivity generated from an unpropped fracture, a propped fracture and acid fracture. The target formation features extreme closure stress and low permeability at a depth of 5000-7000 meters. The efficiency of acid fracturing is challenged by the severe condition of the formation.
The laboratory experiments were performed using the core samples from three wells from the productive interval of the target reservoir. The acid fracturing treatment conditions that have been used in the field were simulated during the laboratory experiments. The fracture conductivity was measured for un-propped, acid-etched, and propped fractures at different closure stresses using an apparatus consisting of a modified API conductivity cell and a load frame The fracture face surface of the intact and acidized core samples was scanned with a profilometer to characterize the change in surface profile to calculate the volume of dissolved rock caused by acid etching, and the initial fracture conductivity under zero closure stress. Conductivity decline as a function of closure stress was recorded and examined during the study.
The results of the comparative study on fracture conductivities showed that the final propped fracture conductivity was higher than the acid fracture conductivity for all of the core samples. Also, the rate of conductivity decline with increasing closure stress was lower for the propped fracture conductivity compared to the acid fracture conductivity. The conclusion was made that the propped hydraulic fractures would retain a greater conductivity under the formation closure stress compared to the acid fractures. Hence, the hydraulic fracturing with proppant would be a more effective stimulation treatment compared to the acid fracturing for improving the wells productivity for the studied reservoir.
Permeability is a rock property which measures the ability of a porous medium to transmit fluids and controls the fluid flow direction and rates. Permeability can be obtained from cores, wireline formation tests (WFT), nuclear magnetic resonance (NMR) logs and well tests.
Typical usages of WFT include measuring formation pressures along the wellbore, taking fluid samples, identifying fluid types and evaluating reservoir structure. Occasionally, WFT is used to replace a drill stem test (DST) in an exploration well. As in well tests, WFT data are measured in situ but, whereas well tests provide an average over a larger formation volume, WFT permeabilities are generally associated with a smaller volume of investigation around the measurement depth. A limitation of pressure transient analyses with WFT, however, is that they often only yield spherical permeabilities, due to short radii of investigation resulting from small rates and short pretest durations. In such a case, anisotropy can be obtained from formation rate analysis (FRA). Pressure transients generated during fluid sampling by WFT tools can have longer radii of investigation and reach radial flow.
In this study, pressure transient analysis (PTA) and FRA techniques are applied first to model generated WFT data, then to an actual gas reservoir using invaded zone and formation fluid properties. PTA derived spherical permeabilities and FRA results are then combined to obtain permeability anisotropy and estimate both horizontal and vertical permeabilities versus depth. These are then upscaled to compare with permeabilities obtained from DST’s.
Various upscaling methods were investigated. It was found that (1) weighted arithmetic average upscaling yields the best results for horizontal permeability (within 20% of DST permeabilities), and (2) harmonic averaging of vertical permeabilities gives the best match over a wide range of anisotropy values.
This study confirms that upscaled WFT permeabilities are representative of the formation permeabilities, provided appropriate upscaling methods and fluid properties representative of the test zone are used in the WFT analysis.