Leak-off Tests Research Articles

Kick tolerance control during well drilling in southern Iraqi deep wells

The importance of kick tolerance in well operations has recently increased due to its implications in well design, in drilling and well control. To study a simple method for the application of kick tolerance concept in an effective way on the basis of field data, this research purpose is to improve knowledge about Kick Tolerance and represents a technical basis for the discussion on revision of standard procedure.
 The objective of this work is to review and to present a methodology of determination the kick tolerance parameters using the circulation kicks tolerance concepts.
 The proposed method allows to know, to evaluate and to analyze the kick tolerance problem in order to make the drilling execution safer and more economical by reducing the probability to have an incident.
 The calculations of presented methodologies were based upon calculated input values such as ppore and pfrac. and not upon measured leak-off test and RFT (less accurate) input values as in traditional methods. The paper also analyses the calculations not with KT parameters only, but it has continued to give the killing operation procedure to such high pressure high temperature (HPHT) wells.

A new approaching method to estimate fracture gradient by correcting Matthew–Kelly and Eaton's stress ratio

Abstract Fracture pressure is one of the most important parameters in wellbore stability. Fracture pressure shows the ability of rock to hold vertical stress before starts to fracture. The application of fracture gradient (FG) affects the well design, such as mud weight profile, casing setting depth, and cementing operation. Fracture gradient could be determined directly by using leak-off test (LOT) and formation integrity test (FIT), and calculation from logging data. There have been a lot of studies in predicting fracture gradient after the fundamental theory of fracture pressure was developed by Hubbert and Willis in 1957. However, most of those studies were performed without considering the geological characteristic, such as precipitation environment, geology structure, and stratigraphy. A new methodology to predict fracture pressure from former calculations, Matthew–Kelly and Eaton, is proposed. The methodology characterized the formation lithology from Poisson's ratio and stress ratio value which is corrected and analyzed by two correcting constants, a and b. As the result, a new value of Poisson's and stress ratio of the formation was generated and the accuracy of fracture gradient was improved. In addition, the flexibility of this methodology indicates that this methodology could be applied in various drilling area.

Numerical Modelling of Extended Leak-Off Test with a Pre-Existing Fracture

Extended leak-off test (XLOT) is one of the few techniques available for stress measurements in oil and gas wells. Interpretation of the test is often difficult since the results depend on a multitude of factors, including the presence of natural or drilling-induced fractures in the near-well area. Coupled numerical modelling of XLOT has been performed to investigate the pressure behaviour during the flowback phase as well as the effect of a pre-existing fracture on the test results in a low-permeability formation. Essential features of XLOT known from field measurements are captured by the model, including the saw-tooth shape of the pressure vs injected volume curve, and the change of slope in the pressure vs time curve during flowback used by operators as an indicator of the bottomhole pressure reaching the minimum in situ stress. Simulations with a pre-existing fracture running from the borehole wall in the radial direction have revealed that the results of XLOT are quite sensitive to the orientation of the pre-existing fracture. In particular, the fracture initiation pressure and the formation breakdown pressure increase steadily with decreasing angle between the fracture and the minimum in situ stress. Our findings seem to invalidate the use of the fracture initiation pressure and the formation breakdown pressure for stress measurements or rock strength evaluation purposes.

Application ofin situstress estimation methods in wellbore stability analysis under isotropic and anisotropic conditions

Estimation of in situ stresses is a key step in many petroleum engineering applications, ranging from wellbore stability to sanding analysis and hydraulic fracturing design. Direct techniques conventionally used to determine in situ stresses are indeed very time consuming and expensive. These measurements would also be restricted as to the depth of acquisition, and generalization of the results to entire rock masses may not yield representative results. In this paper, applications of three indirect methods?Zoback?s polygon, shear moduli, and poroelastic?are studied to assess their applicability in providing reliable stress estimation under isotropic and anisotropic conditions. Determination of elastic, strength, and in situ stress parameters according to the assumption of each method for one of the vertical wells drilled in south Iran indicated that the shear moduli method is an appropriate approach for prediction of maximum horizontal stress within an interval where sufficient field data including leak-off tests are acquired. However, the poroelastic method seems to be a better method in prediction of in situ stresses under anisotropic conditions. This might be due to the presence of excessive shale formations in subsurface layers, causing structural or intrinsic anisotropy-based methods such as poroelastic equations to deliver more accurate results. However, making general conclusions based on studying a single vertical wellbore may not be sufficient, and therefore further studies are required.

Integrated Predrill Pore-Pressure and Borehole-Stability Prediction for Prelude Development

Summary Pore-pressure (PP) and fracture-gradient (FG) predictions were prepared for Prelude development wells in the Browse basin in offshore northwest Australia. The PP forecasts were based on resistivity- and sonic-based models calibrated with pressure measurements and drilling events, such as kicks from existing wells. FGs were based on leakoff tests and loss events from offset wells and were not necessarily equal to either the minimum compressive principal stress (often considered a lower bound to FG) or the formation-breakdown pressure (often considered an upper bound to FG that includes effects of formation tensile strength and near-wellbore hoop stress). The minimum compressive horizontal stress was calculated from lithology-dependent effective-stress ratios. Maximum horizontal stress was inferred from observed breakouts. PP and stresses were combined with formation properties from well logs and laboratory rock-mechanics tests to provide input for elastoplastic (shales) and poroelastic (sands) borehole-stability (BHS) models. These techniques are applicable to exploration, appraisal, or early-development wells that have potential for encountering geopressured formations in high-angle well sections requiring good predrill estimates to adequately plan the casing and drilling programs and determine BHS. The predrill studies can be extended to provide integrated real-time PP and BHS while drilling, and the models can be recalibrated after each well to provide updated predictions for subsequent wells. There are only minor deviations in the predicted PP and FG among the different well locations considered. Common features include potential loss zones in the shallow overburden, pressure ramp within the Jamieson, pressure regression below the Aptian, and near-hydrostatic pressure within the Upper Swan and below. The BHS models indicate that minimum-required mud weight in deviated sections could be up to 20% higher than that required to balance formation PP. In one well that would cross a suspected fault, the risk of fault reopening or reactivation is low.

3-D geomechanical–numerical model of the contemporary crustal stress state in the Alberta Basin (Canada)

Abstract. In the context of examining the potential usage of safe and sustainable geothermal energy in the Alberta Basin, whether in deep sediments or crystalline rock, the understanding of the in situ stress state is crucial. It is a key challenge to estimate the 3-D stress state at an arbitrarily chosen point in the crust, based on sparsely distributed in situ stress data. To address this challenge, we present a large-scale 3-D geomechanical–numerical model (700 km × 1200 km × 80 km) from a large portion of the Alberta Basin, to provide a 3-D continuous quantification of the contemporary stress orientations and stress magnitudes. To calibrate the model, we use a large database of in situ stress orientation (321 SHmax) as well as stress magnitude data (981 SV, 1720 Shmin and 2 (+11) SHmax) from the Alberta Basin. To find the best-fit model, we vary the material properties and primarily the displacement boundary conditions of the model. This study focusses in detail on the statistical calibration procedure, because of the large amount of available data, the diversity of data types, and the importance of the order of data tests. The best-fit model provides the total 3-D stress tensor for nearly the whole Alberta Basin, and allows estimation of stress orientation and stress magnitudes in advance of any well. First-order implications for the well design and configuration of enhanced geothermal systems are revealed. Systematic deviations of the modelled stress from the in situ data are found for stress orientations in the Peace River and the Bow Island Arch as well as for leak-off test magnitudes.

The Role of Shear Failure on Stress Characterization

Leak-off pressure and lost circulation data are generally thought to be reflective of minimum stress. We propose an alternative interpretation should be considered where the data may reflect a shear failure along zones of pre-existing weakness rather than opening of tensile fractures against the minimum stress. This mechanism has been discussed in a small number of borehole stability and hydraulic fracture papers, but has not been widely applied to leak-off test or lost circulation interpretation. In this paper, we will revisit and expand the concept introduced recently by Couzens-Schultz and Chan (J Struct Geol, doi: 10.1016/j.jsg.2010.06.013, 2010) based on abnormally low leak-off tests in an active thrust belt to the analysis of lost circulation observations in modern-day deltaic environments. In the Gulf of Mexico, lost circulations historically are interpreted as a representation of the minimum horizontal stress due to initiating or reopening of a fracture in tensile mode. However, shear failure or fault reactivation can occur at pressures well below the minimum far-field stress that is typically considered a safe upper bound for mud pressure if pre-existing planes of weakness such as faults or fracture networks exist. We demonstrated a mud loss event is shown to be inconsistent with the tensile failure mode in a normal stress environment, but in good agreement with expectations for shear failure along pre-existing faults.

Quantifying in Situ Horizontal Stress in the Niger Delta Basin, Nigeria

AbstractWe have determined the direction and the magnitude of the two horizontal stress components (minimum and maximum) in the Niger Delta Basin, Nigeria from petroleum exploration data from the region. Faults interpreted from a high fold 3D seismic data imply a dominant normal faulting regime. It suggests that maximum horizontal stress (SHmax) is an intermediate principal stress in the basin. The magnitude of the horizontal stress is quantified by two methods: as a function of vertical stress and as a function of overpressure at depth. The scattering of SHmin values estimated from application of the Eaton (1969) method and Leak Off Test (LOT) data is indicative of the SHmin gradient varying with depth in the basin. We propose an inhomogeneous stress field and more than one source of stress in the region based on the result of multiple directions determined from the analysis of 32 borehole breakouts recorded in six wells. We suggest the occurrence of repeated earth tremors in the region is likely to be due to the reactivation of rifted continental crust linking the regional onshore faults along major lineaments.

Seismic and petrophysical evidence of abnormal pore pressure in western Niger delta

A detailed pore pressure evaluation of Tango Field, western Niger Delta, was carried out with the aim of ascertaining depth to overpressure which enables proper well planning and designing in order to reduce cost of exploration and exploitation. The evaluation was carried out using both petrophysical data consisting of sonic, density and resistivity logs obtained in five wells drilled in the area and high resolution-seismic reflection data from which the average and interval velocities were computed. Crossplots were made for well logs data which were fitted with regression curves, and trend lines in order to establish overpressure patterns. Plots of overburden, fracture and hydrostatic gradients with leak off test (LOT), mud weights and modular dynamic tester (MDT) were made to validate the trends established from the crossplots. The results obtained show that normal compaction trends (NCT) were established for all the data used in the analysis and all the wells except well 5 which showed obvious deviations from these trends. Well 5 encountered overpressure at 8,000 ft which was considered earlier than anticipated, hence, it was abandoned. Top of overpressures for wells 2 and 4 were estimated between 9,000 ft and 12, 000 ft respectively. Porosity versus vertical effective stress from the plots confirmed the above depth to overpressure which reveals that the overpressures are primarily generated by disequilibrium compaction.

An analytical expression for the determination of in situ stress state from borehole data accounting for breakout size

Knowledge of the in situ stress state in rock and soil deposits is very important in many problems in civil, mining and petroleum engineering and energy development, as well as in geology and geophysics. The prediction of the response of rock masses interacting with underground structures is highly influenced by the stress field. For example, as pointed out in [1], in civil and mining engineering, in situ stresses control the distribution and magnitude of the stresses around underground openings such as tunnels, mines, shaft or caverns. Stress concentrations in the excavation walls may be large enough to overstress the rock, mobilize the strength of the rock mass and induce failure. On the other hand, tensile stresses in excavation walls may open existing fractures or create new ones which could result in block stability problems. An exact prediction of in situ stress acting over a rock mass, together with its spatial variation, is a very complex topic; the current stress state is a mixed consequence of tectonic conditions and of mechanical effects due to local thermochemo-hydraulic conditions. Due to the complex nature of rocks and rock masses, the stress field is rarely homogeneous and also its time evolution can be significant within a geological formation. Stress state is a symmetric second-order tensor and so it is defined by six independent components, e.g. the three principal stresses and the three principal directions. Stresses in rocks cannot be measured directly and can only be inferred by disturbing the rock. Amadei and Stephansonn [2] presented a detailed summary of the available sources of information from which it is possible to obtain the in situ stress state, involving hydraulic methods (i.e. hydraulic and sleeve fracturing), relief methods, jacking methods, strain recovery methods, borehole failure methods as well as fault-slip data analysis and earthquake focal mechanisms. Zoback [4] proposed an overview of a possible strategy to characterize the stress field: the vertical stress can be determined from the equilibrium in the vertical direction, i.e. by integration of the density logs, while observations of the geometrical arrangement of drilling-induced tensile fractures are an effective way to check whether the vertical stress is a principal stress. The orientation of the other principal stresses can be determined from wellbore observations, recent geologic observations and earthquake focal mechanisms, as well as from stress recovery methods. The magnitude of the minimum principal stress can be estimated from the analysis of hydraulic fracturing and leak-off tests, while the pore pressure can be either measured directly or estimated with some caution from geophysical logs or seismic data. In this paper the vertical stress is assumed to be a principal stress, so that the remaining two directions are supposed to be horizontal. This assumption is reliable for non-active regions or regions already relaxed from the previous tectonical stress. As pointed out by Bell [3], the free surface of sedimentary basins is generally horizontal, so that the principal stress directions are, to a good approximation, horizontal and vertical. From a practical point of view, if the vertical direction is assumed to be a principal one, it is sufficient to know just a horizontal principal direction, since the remaining one is orthogonal to the plane on which the other two are lying. Throughout the paper, Sv will represent the principal vertical in situ stress, SH represents the maximum horizontal in situ stress and Sh represents the minimum horizontal in situ stress, whose magnitude can be evaluated through hydraulic fracturing or leak off tests (except for reverse faulting regimes). Assuming that Sv and Sh are known, the aim of the note is to present a methodology for the definition of some boundaries for

Pressure Analysis of ZK212 Well of Yangyi High Temperature Geothermal Field (Tibet, China)

Pressures are critical for safe drilling of high temperature geothermal reservoir. In this paper, fracturing pressure, formation pressure, leaking pressure and annular friction loss and equivalent circulating density of the first medium-deep geothermal well ZK212 is calculated and analyzed by conducting leakoff test and observing the wellbore water table, and contour map of zero pressure point is drawn by the integration of investigation data in 1990s, which could be used to aid designing drilling fluid system avoiding blowout and fracturing formation.

A workflow for building and calibrating 3-D geomechanical models &ndash a case study for a gas reservoir in the North German Basin

Abstract. The optimal use of conventional and unconventional hydrocarbon reservoirs depends, amongst other things, on the local tectonic stress field. For example, wellbore stability, orientation of hydraulically induced fractures and – especially in fractured reservoirs – permeability anisotropies are controlled by the present-day in situ stresses. Faults and lithological changes can lead to stress perturbations and produce local stresses that can significantly deviate from the regional stress field. Geomechanical reservoir models aim for a robust, ideally "pre-drilling" prediction of the local variations in stress magnitude and orientation. This requires a numerical modelling approach that is capable to incorporate the specific geometry and mechanical properties of the subsurface reservoir. The workflow presented in this paper can be used to build 3-D geomechanical models based on the finite element (FE) method and ranging from field-scale models to smaller, detailed submodels of individual fault blocks. The approach is successfully applied to an intensively faulted gas reservoir in the North German Basin. The in situ stresses predicted by the geomechanical FE model were calibrated against stress data actually observed, e.g. borehole breakouts and extended leak-off tests. Such a validated model can provide insights into the stress perturbations in the inter-well space and undrilled parts of the reservoir. In addition, the tendency of the existing fault network to slip or dilate in the present-day stress regime can be addressed.

Drilling and Completing Cascade and Chinook Wells: A Case History

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24179, ’Drilling and Completing Cascade and Chinook Wells: A Design and Execution Case History,’ by Flavio Dias De Moraes, Petrobras; Oswaldo Moreira, Petrobras America; Ziad Haddad, FOI Technologies; Scott Ogier and Jonathan Shipley, SPE, Cherokee Offshore Engineering; Mauricio Rebelo, Petrobras; and Fernando Gama, Petrobras America, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. During the design, implementation, and operation of the Cascade and Chinook (C&C) field development project in ultradeep water in the Lower Tertiary play of the Gulf of Mexico (GOM), the technical limits of single-trip multizone (STMZ) frac-pack systems were pushed to depths greater than 27,000 ft using high fracture rates and high-strength proppants; knowledge was gained from ultrahigh-pressure (greater than 20,000 psi) tubing-conveyed perforating systems; and well-design criteria suitable for high-drawdown (more than 12,000 psi) production operations were demonstrated. Introduction The C&C development plan in the GOM is one of the most technologically challenging and complex projects ever implemented by Petrobras. This project uses the first floating production, storage, and offloading vessel in operation in US waters at a water depth of 8,200 ft. The C&C subsea infrastructure considers the use of subsea manifolds, rigid flowlines, pipe-in-pipe pipelines, and freestanding hybrid risers. These two fields are 15 miles apart and share several characteristics such as depth, lithology, and reservoir similarities. The Wilcox 1 (Eocene) and 2 (Paleocene) sands belong to the Lower Tertiary geologic period and are part of the latest exploratory frontier in the GOM. At least 12 discoveries have been made in the Lower Tertiary, holding a potentially recoverable volume of several billion bbl of oil, highlighting the importance of this technology development for the industry. These reservoirs are characterized by a considerable thickness of intercalated sandstones and shales. The reservoirs show low horizontal permeability (less than 100 md) and poor vertical communication between sand layers. Other characteristics include a very high static formation pressure, a maximum temperature of 256°F, and a low gas/oil ratio. The produced oil has carbon dioxide concentration in the gaseous phase of less than 1.5%, and there is no evidence of hydrogen sulfide contamination. Drilling Design The casing design was based on delivering an 8½-in.-internal-diameter casing at total depth (TD) to accommodate the completion design. In this design, each string is run to its approximate design limit to maximize leakoff-test (LOT) values. One of the most important strategies of the C&C wells was the elimination of the 11⅞-in. liner, which prevents achieving adequate circulation rates for a successful primary cement job on the 10⅛-in. production casing.

Present-day stress of the central Persian Gulf: Implications for drilling and well performance

Abstract The present-day state of stress in the Persian Gulf is poorly understood but has significant impacts on well drilling and performance. The upper Permian to lower Triassic formation of Kangan/Dalan, Persian Gulf, exhibits a complex structural context in the neighborhood of the Oman Mountains and the Zagros orogenies. This formation is divided into four reservoir layers (K1 to K4) where three main lithologies (limestone, dolomite and anhydrite) are alternating. We conduct an analysis of the present-day stress and natural fractures at the wellbore using full-bore FMI logs, leak off test and density logs. For this purpose, borehole breakout and tensile fracture data are used to determine orientation of SH. Furthermore, density log, leak-off test and Kirsch equation for tensile fracture formation in the wellbores are used to calculate the magnitude of Sv, Sh and SH, respectively. Vertical stress (Sv) gradient at 3100 m depth approximates 20 MPa/km (2.9 psi/m), indicating a bulk density of 2.04 g/cm3. A total of 131 drilling induced tensile fractures and 21 breakouts with an overall length of 262 m are observed in two wells, indicating a mean maximum horizontal stress (SH) orientation of N53° (± 18.45°) for drilling-induced tensile fracture (DITF) data and N50° (± 10.79°) for breakout data. The mean orientation of SH rotates counterclockwise with depth from K2 (N70° ± 4.2°) to K4 (N40° ± 5.1°) reservoirs. Noticed correlation between these data and stress orientations from earthquake focal mechanism solution, first of all, indicates that the stresses are linked to the resistance forces generated by the Arabia–Eurasia collision at the Zagros orogeny and secondly confirms the reliability of focal mechanism solution data near continental collision zones. In the Kangan/Dalan Formation, the NW–SE main open fracture direction is found as a common regional direction which is sub-perpendicular to the present-day maximum horizontal stress. Minimum horizontal stress (Sh) gradient in reservoir sections is estimated to be equal to 17 MPa/km (2.5 psi/m). The concluded strike–slip stress regime (SH > Sv > Sh) in the study area is consistent with the compressive regime in the Zagros thrust–fold belt. The present-day stress in the Kangan/Dalan Formation has implications for wellbore stability, lost circulation and well Inflow Performance Relationship (IPR). Wells are more unstable if deviated toward the Sv direction, whereas well productivity and mud loss increase in wells deviated toward SH, which conveys the idea of a strike–slip faulting effect tends to keep the natural fractures open in that direction.

Anisotropic Porochemoelectroelastic Solution for an Inclined Wellbore Drilled in Shale

The porochemoelectroelastic analytical models have been used to describe the response of chemically active and electrically charged saturated porous media such as clay soils, shales, and biological tissues. However, existing studies have ignored the anisotropic nature commonly observed on these porous media. In this work, the anisotropic porochemoelectroelastic theory is presented. Then, the solution for an inclined wellbore drilled in transversely isotropic shale formations subjected to anisotropic far-field stresses with time-dependent down-hole fluid pressure and fluid activity is derived. Numerical examples illustrating the combined effects of porochemoelectroelastic behavior and anisotropy on wellbore responses are also included. The analysis shows that ignoring either the porochemoelectroelastic effects or the formation anisotropy leads to inaccurate prediction of the near-wellbore pore pressure and effective stress distributions. Finally, wellbore responses during a leak-off test conducted soon after drilling are analyzed to demonstrate the versatility of the solution in simulating complex down-hole conditions.

In-situ stress and fault reactivation associated with LNG injection in the Tiechanshan gas field, fold-thrust belt of Western Taiwan

The Tiechanshan gas field located in the fold-thrust belt of western Taiwan was depleted and converted for underground storage of Liquefied Natural Gas (LNG) decades ago. Recently, CO2 sequestration has been planned at shallower depths of this structure. We characterize the in-situ stresses from over 40 wells and assess the leakage potential through fault reactivation in response to LNG-injection increased pore-pressure. The formation pore pressure (Pf), vertical stress (Sv), and minimum horizontal stress (Shmin) are measured from repeated formation tests, density logs, and hydrofrac data including leak-off tests and fluid injection. Formation pore pressures are hydrostatic above depths of 2km, and increase with local gradients of 14.02 and 21.26MPa/km above and below 3.2km, respectively. Extremely high pore pressures (λp=0.8) are observed at depths below 3.8km. Lower than normal pressures (average 9.47MPa/km) are observed in the gas-bearing reservoir of the Talu A-sand. The gradient of Shmin is ∼17.46MPa/km or equivalent to 0.74 of Sv (∼23.60MPa/km). A detailed structure contour map of the top of the A-sand, combined with the measured Shmin and Sv, show that the stress state in the Tiechanshan field is predominantly strike-slip stress regime (SHmax>SV>Shmin). An upper-bound value of the maximum horizontal stress (SHmax) constrained by frictional limits and the coefficient of friction (μ=0.6) is about 27.36MPa/km. Caliper logs from two wells show that the mean azimuth of preferred orientation of borehole breakouts are in ∼028°N. Consequently, the maximum horizontal stress axis tends 118°N, which is sub-parallel to the far-field plate-convergence direction. Geomechanical analyses of the reactivation of pre-existing faults at the depths of the LNG reservoir sand indicate that all faults are stable at the present stress state. Sensitivity analyses indicate that ∼5.9MPa excess pore pressure would be required to cause the optimal oriented f1 fault to reactivate. This corresponds to LNG column heights of ∼760m (density=∼790kg/m3), whereas the height of structural closure of the A-sand does not exceed 400m. Therefore, it is unlikely that LNG injection will reactivate f1 fault.

Apps and the Digital Oil Field

App technology The oil and gas industry tends to be resistant to marketing fads. If a software phenomenon such as the app cannot help get oil and gas out of the Earth safer, faster, and more economically, then the industry will not use it. This may be why, of the hundreds of thousands of apps now publicly available, only a few dozen are devoted to the industry. Apps Developed for the Oil and Gas Industry None of the online app stores has a separate category for the petroleum industry. Oil and gas apps are primarily housed under app stores’ business, education, productivity, or reference headings. While an app must meet certain software standards to be included in an app store, the actual content receives no vetting. So, beyond the name and reputation of the company or person providing the app, no assurance is provided on the accuracy of the app’s information, mathematical formulas, or simulation parameters. Oil and gas industry apps comprise the following five categories: Those devoted to marketing materials—These marketing collateral materials take the place of printed catalogs, annual reports, brochures, and data sheets. While companies have made such materials available on their websites ever since the Web began rising in prominence in the early 1990s, the primary advantage of accessing them via a smartphone or tablet lies in the greater portability of the devices themselves, as well as the ability for updated material to be added at any time. For example, Aker Solutions recently implemented a smartphone app for its wireline tractor catalog. On a tablet, this is downloaded as a portable document format (PDF) file that is accessible through a book library app. In another example, Tenaris has created its own TenarisLibrary, featuring a complete and integrated package of its available marketing literature and videos. These appear in a variety of languages, and access can be tailored to individual interests. Calling it a “dynamic library,” Tenaris writes, “Each user is invited to create their own customized library to navigate the material once disconnected from the Internet.” Those that supply computations—Designing a drilling program and constructing, drilling, and completing a well demand input of a huge number of variables that can be manipulated using mathematical formulas and computations. Each variable rests upon a solid foundation of physical reality, including measured depth, pipe inner and outer diameter, downhole pressure and temperature, azimuth, mud weight, rate of penetration, and weight on bit. Some computationally based apps—including Halliburton’s eRedBook and eChartBook and Schlumberger’s Smith Bits Quick Calc Hydraulics—are of use in the field. Others—such as Wellcontrol.com.br’s Well Control, Leak-Off Test, and Drilling simulators—are useful as educational tools.

Estimation of horizontal stress magnitudes and stress coefficients of velocities using borehole sonic data

We described a nondestructive method to estimate the maximum and minimum horizontal stresses and formation nonlinear elastic constants using sonic data from a vertical wellbore. This method for the estimation of horizontal stress magnitudes consists of using radial profiles of the three shear moduli obtained from the Stoneley and cross-dipole sonic data in a vertical wellbore. These shear moduli change as a function of formation stresses, which in turn change as a function of the radial position away from the wellbore. Two difference equations were constructed from the three far-field shear moduli and the other two were constructed from differences in the shear moduli at radial positions with different stresses in the presence of near-wellbore stress concentrations. Outputs from this inversion algorithm included the maximum and minimum horizontal stress magnitudes, and two rock nonlinear constants referred to a local hydrostatically loaded reference state. The underlying acoustoelastic theory behind this inversion algorithm assumes that differences in the three shear moduli are caused by differences in the formation principal stresses. Additionally, the orientation of the maximum horizontal stress direction was identified from the fast-shear azimuth in the presence of a dipole dispersion crossover. Hence, the principal horizontal stress state was fully determined. Good agreement was obtained between the predicted minimum horizontal stress magnitude and that measured from an extended leak-off test in a vertical offshore wellbore in Malaysia. One of the nonlinear constants was obtained from differences between compressional velocity at two depths caused by differences in the overburden stress and the maximum and minimum horizontal stresses. Estimates were obtained for the stress coefficients of the compressional, fast-shear, and slow-shear velocities referred to a local reference state. These stress coefficients of velocities helped in the interpretation of observed time-lapse changes in seismic traveltimes caused by fluid saturation and reservoir stress changes.

New constraints on stress and fracture orientations in the Shipwreck Trough, Otway Basin: implications for conventional and unconventional exploration and production

A detailed understanding of the in-situ stress tensor within energy-rich basins is integral for planning successful drilling completions, evaluating the reactivation potential of sealing faults and developing unconventional plays where fracture stimulation strategies are required to enhance low permeability reservoirs. Newly available leak-off test results interpreted using a new method for analysing leak-off test data constrains the minimal horizontal stress magnitude for the offshore Shipwreck Trough wells to be ∼20 MPa/km, which is similar to the vertical stress magnitude derived from wireline data for depths shallower than ∼2–2.5 km. Breakouts interpreted from image log data reveal a ∼northwest–southeast maximum horizontal stress orientation and formation pressure tests confirm near-hydrostatic conditions for all wells. The new method for analysing leak-off test data has constrained the upper limit of the maximum horizontal stress magnitude to be the greatest, indicating a reverse-to-strike-slip faulting regime, which is consistent with neotectonic faulting evidence. Petrophysical wireline data and image log data to characterise extant natural fracture populations within conventional reservoirs and stratigraphic units that may be exploited as future unconventional reservoirs have also been used. These fracture sets are compared with possible fracture populations recognised in contiguous, high-fidelity 3D seismic datasets using a new method for identifying fracture systems based on attribute mapping techniques. This study represents the first of its kind in the Otway Basin. Combined analysis of the in-situ stress tensor and fracture density and geometries provides a powerful workflow for constraining fracture-related fluid flow pathways in sedimentary basins.

Reassessing the in-situ stress regimes of Australia's petroleum basins

Previous in-situ stress studies across many of Australia’s petroleum basins demonstrate normal fault and strike-slip fault stress regimes, despite the sedimentary successions demonstrating evidence for widespread Miocene-to-Recent reverse faulting. Seismic and outcrop data demonstrate late Miocene-to-Recent reverse or reverse-oblique faulting in the Otway and Gippsland basins. In the Otway Basin, a series of approximately northeast to southwest trending anticlines related to reverse-reactivation of deep syn-rift normal faults, resulting in the deformation of Cenozoic post-rift sediments are observed. Numerous examples of late Miocene-to-Recent reverse faulting in the offshore Gippsland Basin have also been observed, with contractional reactivation of previously normal faults during these times partially responsible for the formation of anticlinal hydrocarbon traps that host the Barracouta, Seahorse and Flying Fish hydrocarbon fields, adjacent to the Rosedale Fault System. A new method for interpreting leak-off test data demonstrates that the in-situ stress data from parts of the Otway and Gippsland basins can be reinterpreted to yield reverse fault stress regimes, consistent with the present-day tectonic setting of the basins. This reinterpretation has significant implications for petroleum exploration and development in the basins. In the Otway and Gippsland basins, wells drilled parallel to the orientation of the maximum horizontal stress (σH) represent the safest drilling directions for both borehole stability and fluid losses. Faults and fractures, striking northeast to southwest, previously believed to be at low risk of reactivation in a normal fault or strike-slip fault stress regime are now considered to be at high risk in the reinterpreted reverse fault stress regime.