Water is the wetting phase. Figure 1.5 – Primary drainage, imbibition, and secondary drainage for an oil/water system in which the oil and water wet the solid surface equally. Figure 1.6 – Primary drainage and imbibition for unconsolidated dolomite powder (the lines merely connect the data). These authors wrote capillary pressure as the negative of Eq. 4 because oil was the wetting phase for most of the tests. The legend gives contact angles measured through the water phase (in degrees). Leverett and coworkers, based on the evaluation of gas/water capillary pressure data for drainage and imbibition in unconsolidated sands, proposed the following definition: ....................(15.6) The function j(Sw), defined in Eq. 15.6, is known to many as the "Leverett j-function." The j-function is obtained from experimental data by plotting against Sw. The combination is often considered an estimate of the mean hydraulic radius of pore throats.
Relative permeability and capillary pressure defines relative permeabilities as dimensionless functions of saturation with values generally ranging between 0 and 1. Relative permeability is important for estimating the flow of reservoir fluids. The semilog scale of Figure 1 is convenient for reading the relative permeabilities less than 0.05. For example, the relative permeability that increases in the direction of increasing oil saturation must be the oil relative permeability. The endpoints of the relative permeabilities in Figs. 1 and 2 are defined by the critical gas saturation Sgc and the residual oil saturation Sor. Common names and symbols for some saturation endpoints are listed in Table 1.
Analytically-derived criteria are presented for the orientation of fracture initiation from horizontal wellbores drilled in porous-permeable (poroelastic) media. This involves drilling-induced tensile fractures (DITFs) from non-perforated wellbores and completion-induced hydraulic fractures (CIHFs) from perforated wellbores with cylindrical perforation geometry. The criteria are developed considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of longitudinal fractures and another for the initiation of transverse fractures, with respect to the wellbore. In-situ stress state, wellbore pressure, and the formation's mechanical and poroelastic properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
The DITF orientation can be used to constrain the magnitude of the maximum horizontal stress; the most difficult aspect of the in-situ stress tensor to constrain. Transverse CIHF initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal initiation occurs at comparatively higher wellbore pressures. However, transverse CIHF initiation occurs more frequently than transverse DITFs, because the presence of perforations aids transverse fracture initiation. The region of the in-situ stress states where transverse initiation is promoted is shown in dimensionless plots for perforated and non-perforated wellbores. Fracture initiation criteria for specific cases presented can be used to predict the orientation of fracture initiation in oilfield operations.
The orientation of CIHFs controls the productivity of hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Fracture initiation often follows a plane different to the final fracture propagation plane. Stress re-orientation in the near-wellbore region may promote fracture initiation of different orientation than the orientation dictated by the far-field stresses. The range of in-situ stress states in which transverse fracture initiation is promoted increases as Biot's poroelastic coefficient,
ABSTRACT: Fracture initiation often follows a plane different to the final fracture propagation plane. Stress reorientation in the near-wellbore region may promote fracture initiation of different orientation than the one dictated by the far-field stresses. A three-dimensional numerical analysis using a geomechanical model is performed to assess an analytical orientation criterion for fracture initiation in perforated wellbores. This is accomplished by considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of transverse fractures and another for the initiation of longitudinal fractures. In-situ stress state, wellbore pressure, perforation geometry and the formation’s mechanical properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
We find that it is likely for typical hydraulic fracture treatments to achieve longitudinal fracture initiation in horizontal wells as transverse initiation will only occur over a narrow window of conditions including low wellbore pressure at breakdown and formation tensile strength. In contradiction with existing analytical models, the numerical study shows that the tangential stress which induces transverse fracture initiation is a function of wellbore pressure just as the stress inducing longitudinal fracture initiation. This makes the breakdown pressure window for transverse fracture initiation smaller compared to the prediction of the analytical model.
Hydraulic fracturing is a reservoir stimulation method used since the 1940s. This is accomplished by high pressure fluid injection which either creates cracks that propagate through the rock matrix or can reopen natural pre-existing fractures. Commonly, 20 to 40 fracture stages are placed in a horizontal well with four or more fractures pumped per stage simultaneously. The industrial impact of this technology has been massive and is responsible for the advances in the development of tight unconventional petroleum resources such as shale gas and oil (Michael, 2014 and Michael, 2016a).
The hydraulic fracture orientation controls the well productivity from hydrocarbon reservoirs. In this study we investigate critical parameters controlling the orientation of hydraulic fracture initiation in perforated horizontal wellbores. Productivity from low permeability (“tight”) formations is greatly improved having multiple fractures oriented transversely rather than longitudinally relative to a horizontal wellbore. This is useful for completion design engineers; when targeting low permeability formations, horizontal wells should be made to induce multiple transverse fractures, as opposed to longitudinal fractures which are more effective in higher permeability formations.
Interpretation of logs from an exploration pilot well and a lateral drilled from the pilot in the Late Cretaceous Natih formation in the Sultanate of Oman was used for designing a multistage hydraulic fracturing treatment. A high-tier logging suite including borehole image, advanced dipole sonic, geochemical, and triple combo data was acquired in both wellbores. The objective of the pilot hole was to select the best landing point in terms of reservoir quality (RQ) and completion quality (CQ) so that a horizontal well could be drilled and multistage stimulations performed in the organic-rich Natih B source rock.
In contrast to much of North America, significant tectonic forces are frequently present in this region. The geomechanical setting might thus strongly affect hydraulic fracture initiation, propagation and proppant placement. It therefore plays an important role in lateral landing point selection. Borehole images, integrated with petrophysical and geomechanical log properties, were used to identify the optimum landing zone. Breakouts as well as longitudinal and transverse drilling-induced fractures were identified on the pilot borehole images over the Natih Formation, indicating a large horizontal stress anisotropy and a compressional tectonic setting. An interval from which vertical hydraulic fractures would initiate at low initiation pressure and grow vertically to contact intervals with good RQ was selected as the target lateral landing point. Image and dipole sonic data were acquired in the horizontal well, and both longitudinal and transverse induced fractures were identified. Those data were used to selectively place hydraulic fracturing stages. Diagnostic injection tests on each stimulation treatment confirmed low fracture initiation pressures and the creation of vertical hydraulic fractures, thus validating the selection of both the landing point and the location of the hydraulic fracture initiation points. All treatments were successfully placed to completion.
This paper demonstrates that a workflow based on the combination of image and dipole sonic logs in both a pilot well and a lateral drilled from the pilot enables the creation of vertical hydraulic fractures at moderately low initiation pressures and successful placement of stimulation treatments in the lateral. This technique shows promise for effective hydraulic fracturing in regions where significant tectonic forces are present.
Rana, Rohit (Independent Geomechanics and Pore Pressure Consultant) | Hansen, Kirk S. (Shell India Markets Private Limited) | Kandpal, Jyoti (Shell India Markets Private Limited) | Kumar, Rajan (Shell India Markets Private Limited) | Schutjens, Peter (Shell India Markets Private Limited) | Muro, Leytzher (Shell India Markets Private Limited) | Rees, Daniel (Brunei Shell Petroleum Co Sdn Bhd) | Latief, Agus I. (Brunei Shell Petroleum Co Sdn Bhd)
Knowledge of the in-situ stress state and how it varies with reservoir depletion is important for the design and execution of in-fill drilling. This paper highlights the key geomechanical aspects and their usage in planning of wells through severely depleted (up to 25 MPa) and overpressured zones within a very short depth interval (few 10s of m), in an onshore gas field in Brunei. With focus shifting from oil to deep-gas development, drilling complications include risks of wellbore instability, excessive mud loss and internal blowouts, as well as differential sticking in the depleted reservoirs. Moreover, fracturing of the depleted sands while drilling infill wells carries the risk of jeopardizing production at nearby producing wells because of locally altered flow paths. The risks were evaluated by application of empirical and analytical geomechanical models of stress changes with depletion, and by elasto-plastic finite element models of borehole instability (collapse) due to shear failure.
Our results show that for an average depletion rate of 1 MPa/year, the drilling window (difference between maximum allowable mud weight controlled by fracture pressure and minimum mud weight controlled by formation pore pressure or borehole collapse pressure, whichever is greater) is likely to remain open for the coming 12 years. Minifrac or extended leak-off tests at different stages of field development should be taken to monitor stress changes within the reservoirs and provide updates for calibration of the geomechanical model.
Next to showing the geomechanical model results and their application to drilling, we demonstrate the refinement of pore pressure/fracture pressure predictions (i.e. narrowing down the uncertainty in the drilling window) for mature fields where producing "from the bottom up" has not been feasible. We also indicate how risks associated with drilling through depleted/undepleted reservoir sequences in a single hole section can be managed to as low as reasonably practicable with the help of geomechanical input. These results "open the door" for accessing deeper potential pay zones by drilling through severely depleted formations.
Haghighi, M (The University of Adelaide) | O'Reilly, DI (Chevron Australia Pty Ltd, The University of Adelaide) | Hunt, AJ (Chevron Australia Pty Ltd) | Sze, ES (Chevron Australia Pty Ltd) | Hopcroft, BS (Chevron Australia Pty Ltd) | Goff, BH (Chevron Australia Pty Ltd)
This paper demonstrates how good technical evaluations and focused operational application can enhance the value of a mature asset. The Windalia reservoir underlies Barrow Island (BWI), situated 56 km from the coast of Western Australia, and has produced oil since 1965. Waterflooding commenced shortly after initial production, in 1967, and remains the main drive mechanism in the field today. Throughout the life of this onshore field, water injection and oil production have varied according to asset strategy and economic conditions. In this case study, we share how recent improvements made in the areas of Reservoir Surveillance and Operations activities have increased water injection efficiency and total oil recovery.
Through the use of new methods and workflows, the BWI Sub-Surface team was able to target specific areas of the field to distribute water to in order to increase injection and maximise oil production. For example, new workflows were built with the real-time PI monitoring system to analyse Pressure Fall Off (PFO) tests from each of the 147 waterflood patterns in detail. Capacitance-Resistance-Modeling was also leveraged to guide individual well target injection-rates. Operationally, several projects were also initiated to increase water injection into the right areas of the field.
The new Reservoir Management approach has significantly increased the volume of water being injected into the areas of need, supporting improved levels of oil production. For the first time in almost 10 years, the stream-day water injection rate has exceeded 90,000 bwipd. The results from PFO transient interpretation and pattern balancing proved effective in directing water to low-pressure, high-GOR areas of the field. They also provided valuable information about formation perm-thickness and skin. The phenomenon of water-cycling was also largely avoided, owing to close monitoring of production well tests and water injector transient surveys.
The present work addresses reservoir and operational aspects of Australia's largest active waterflood. The lessons shared are highly applicable to a low oil price environment, as they show how fit-for-purpose and low-cost acquisition of reservoir data can lead to improved field performance.
A collaborative study has recently completed a storage capacity prospectivity assessment and pre-competitive data acquisition program in the southern margin of the offshore Gippsland Basin, Australia. Potential CO2 storage sites that could become available in the next ~25 years will be restricted to sites in the nearshore and southern parts of the offshore Gippsland Basin. This is in order to minimize possible resource interactions with ongoing petroleum production and low salinity groundwater in the northern and central parts of the basin. The injection target, the Latrobe Group has been identified as a suitable candidate for large-scale CO2 geological storage.
As part of the storage capacity assessment, a detailed geological model of the Latrobe Group sequence was constructed in an area of the southern margin of the basin. The model evaluates two main east-west-trending fault systems separating the model into three structural segments: a deep depocentre, flanked by the Southern Terrace, and thin Southern Platform. The sedimentary sequences comprise coastal plain to shallow marine sandstone deposits interbedded with laterally continuous coals and mudstones, which act as seals and baffles of varying quality. Uncertainty in the reservoir architecture and the impact on connectivity of the permeability field was assessed by way of multiple model realizations. The model was then used as the basis for a series of capacity and injectivity estimations employing theoretical, analytical, and numerical flow simulation modelling techniques.
At the highest end, for an area excluding the platform and assuming low sweep efficiency, estimates of the theoretical CO2 storage capacity ranged between 865 million tons (Mt) and 2,800 Mt. For the analytical model estimates were up to 900 Mt and numerical methods estimates were in the order of 200 Mt to 550 Mt assuming 3 injection wells in a 40 × 40 km area over 30 years. All of the results are highly sensitive to the estimation method used and input provided such as, net area defined, injection interval selected, uncertainties on fault seal, and boundary conditions. However, the insights gained from the numerical modelling studies in the region have indicated that carbon storage injection has the greatest potential south-west of the Bream field. After 1,000 years post injection, accumulations of mobile gas can be observed at different locations within the model, suggesting several vertical and lateral pathways. Key outcomes of the simulations support the concept of the southern margin of the Gippsland Basin being prospective for further CO2 storage exploration, namely that it is feasible to achieve injection and containment of commercial scale volumes of CO2 in parts of this region without adversely impacting existing resources.
ABSTRACT: Hydraulic fracturing (HF) stimulation of oil wells have made possible the current flourishing oil production from pay zones. Longer initial fractures length and shorter spacing increases oil production. However, these operations usually are expensive and may even cause interference and subsequent reduction in oil production. Analytical models do not consider fracture interference and assume equal fracture half-lengths. Therefore, optimizing initial fractures geometry using numerical methods is of high importance in a successful HF operation. Various geometrical parameters of initial HF cracks including patterns, spacings and crack lengths have been modeled using a higher order displacement discontinuity method (HODDM) in a horizontal oil well. Some of the most encountered problems in HF processes such as fracture interference and fracture arrest have been detected through numerical simulations. Considering several different loading cases, most suitable crack geometrical parameters have been obtained. The results are also confirmed by in-situ measurements available in the literature.
The combination of multiple hydraulic fracturing (HF) and horizontal drilling has led to an enhanced production of hydrocarbon from reservoirs with low permeability. The primary objective of HF is to improve the natural connections of wellbores and reservoirs. Many fundamental aspects in HF are yet ambiguous and require further investigations. One of these aspects is the arrangement and orientation of the initial perforations. The orientation of a wellbore and the in-situ stress regime have important effects on the initiation of a HF process (Rahman et al. 2000, Abdollahipour et al. 2016).
Multiple transverse hydraulic fractures are the main contributor to a high hydrocarbon production (Freeman et al. 2013, Zhao et al. 2014, Guo et al. 2014, Abdollahipour et al. 2016). Optimization of the hydraulic fracture parameters such as the fracture spacing and fracture half-length is of paramount importance.
Previous works have established that higher number of fractures in the formation around the wellbore results in a faster hydrocarbon production (Kalantari-Dahaghi 2011, Fazelipour 2011). In some cases, more than 20 fracture stages have been tried in a horizontal well in order to increase the fracture contact with the formation, and to produce high initial rates.The studies have suggested that the initial production increases linearly with the number of fractures but a high flow rate is not sustainable and declines sharply once the fractures interfere over a given lateral length (Castaneda et al. 2010, King 2010). It is obvious that the longer the initial fracture length and the shorter their spacings, the higher the oil production will be.
Esso Australia Resources Pty Ltd, along with joint venture partner BHP Billiton (Bass Strait) Pty Ltd, recently undertook drilling of development wells in order to access new reservoirs in the Gippsland Basin, offshore Victoria. This development of new reservoirs required confirmation of the drive mechanisms in the different stacked reservoirs to finalise the completions for each of the wells.
To confirm the pre-drill understanding of the reservoir behavior in this particular field the logging-while-drilling formation pressure testing technology was deployed, in a total of five (5) wells, throughout the development drilling campaign. The main objectives were to confirm fluid type and connectivity across the penetrated reservoirs, comparison of the logging-while drilling (LWD) data with existing wireline datasets to confirm drive mechanism and to aid in determining fluid contacts within the penetrated reservoirs.
This paper discusses the advantages and benefits of deploying a formation tester in a LWD environment, the results that were achieved and how these objectives were met. Formation pressure while drilling technology provides many advantages for formation evaluation capabilities. In particular operators can collect formation pressure measurements in highly deviated wells whilst reducing operational risks and minimizing costs. The measurements are acquired with the same technology that is used in equivalent wireline formation testers and therefore provide the same high quality data but in a drilling environment. In addition the LWD formation tester has proprietary features to optimize achieving valid pressure measurements during each deployment which will be discussed further in this paper.
As a result of the five successful separate runs a better understanding of the drive mechanisms of the separate reservoirs was achieved which enabled adjustment and optimization of the completion design. In addition, the formation pressure data was used to determine fluid contacts within reservoirs and aid in resolving LWD petrophysical log ambiguity.