The recent, sustained depression in global oil prices has driven a significant reduction in upstream Exploration and Production (EandP) expenditure, particularly in the capital-intensive offshore environment. The high costs traditionally associated with EandP development projects, specifically in subsea developments, have driven a requirement for the adoption of technologies that not only increase the efficiency of the well construction process, but also reduce the total number of wells required, whilst increasing production rates and recoverable reserves. Building on recent industry experiences with the varying multilateral systems available, Woodside implemented the use of an alternative innovative multi-lateral system, which has gone through multiple evolutions and marked improvements in system reliability and installation efficiency compared to Woodside's previous multilateral experience. The latest evolution of this system has been implemented during the construction of multi-lateral wells for the Greater Enfield Project (GEP). Within GEP, the Norton over Laverda (NoL) field development comprises three tri-lateral production wells (namely NoL01, NoL02 and NoL03). Norton field is an offset to the Vincent field, which employed an alternative multi-lateral completion design. On average, the Norton multi-lateral well operations were executed 15-30% faster than previous comparable Woodside installations. This has been attributed to the application of operational learnings from the previous Vincent multi-lateral development and the implementation of the new system. These wells were constructed in water depths of > 800 m, the deepest for such a system globally. Of the three wells, NoL01 and NoL02 were constructed well under budget, and ahead of schedule. NoL02 was constructed in a time that benchmarked as the fastest well per 1,000 m versus basin offsets. NoL03 was completed within budget, whilst having faced two major NPT (Non-Productive Time) events (ultimately resolved using world first solutions for the given system). This paper will discuss the successes, challenges experienced, and lessons learned during the installation of the three Norton tri-laterals. This field is a prime example of how new technology and the installation practices for multilateral systems within the operator's assets of the North-West margin of Australia have improved over time.

B Field Overview and Background Located in the South China Sea, B oil field was first discovered in 1971 and has been in production since 1982; it is located in offshore of Sarawak, Malaysia, with a water depth of approximately 70 metres. The field has an interval of over 7000 ft. of stacked reservoir sands and thin continuous shale layers, making up approximately 165 individual reservoir units with Late Miocene to Early Pliocene in age, with the stratigraphic intervals reservoir section. With the objective to find a technically and economically viable enhanced oil recovery (EOR) development concept for B oil field, a feasibility study was conducted by taking several EOR strategies into considerations – low-salinity waterflood, chemical EOR, and immiscible water alternating gas (IWAG). By evaluating individual layers of the field, the study concluded with a recommendation to implement EOR via IWAG on EF reservoirs on the basis of value, timeline, and flexibility for future EORs; IWAG would yield the best result from technical and economical point of view, and also with the ability to be implemented as earliest as possible. The theory behind IWAG implementation in the field is that the gas component of IWAG injection will help to sweep oil that is left along the top of reservoir sands due to poor water-oil mobility ratio and gravity effects, and due to the fact that gas moves quickly in the reservoir, the water component of IWAG injection will come into assistance by controlling gas mobility and maintaining reservoir pressure as more drainage points are introduced into the reservoir. Additionally, water injection provides the control to improve the aquifer's sweep, three-phase hysteresis effects and reduced residual oil (in gas) is expected to improve recovery mobilizing more oil in the reservoir, and gas injection may also assist to drain oil that are trapped in attic accumulations. In B field, IWAG injection involves gas and water injections into wells that are located down-dip of the reservoir. Out of four IWAG injector wells in the recent B field drilling campaign, one well was selected to be equipped with a Distributed Temperature Sensing (DTS) system after considering the following benefits that the DTS system would provide: Conformance monitoring specifically for water to qualitatively identify which sand the water is being injected to or any potential internal crossflow Quantitative flow into each reservoir layer derived from warm-back analysis for the short term and hot-slug propagation for the long term instead of running wireline production logging tool (PLT) Hydraulic fracturing profiling to prevent the formation from fracturing unintentionally due to the water hammer effect or cooling of formation with injection water (i.e., thermal fracture); inversely, when zonal fracturing is intentional and required, profiling to gauge effectiveness and fracture spread Real-time injection issues or zonal anomaly identification to eliminate the need to perform well intervention to obtain information which often results in delayed action Injected gas or water fluid front monitoring when combined with existing DTS in producer wells Reduced intervention risks in a highly deviated well that could lead to fish in hole and potential workover

Unconventional gas exploration in the Cooper Basin, Australia, has historically concentrated on fracture stimulation of tight gas sandstones within mapped structural closures. In drilling these sandstones, and other clastic reservoir targets, it has been recognised for many years that the Permian coal measures of the Toolachee, Epsilon and Patchawarra Formations record high levels of gas, often in excess of 4000 units, encountered at depths between 2500 and 3500m. Unlike shallower Coal-Seam-Gas reservoirs, which rely on de-pressuristion through de-watering to liberate adsorbed gas from the kerogen surface, deep coals are a "dry" system in which the free gas component is produced via kerogen and fracture permeability. However maintaining a consistent and commercial flow rate from deep coals alone remained enigmatic until the first dedicated fracture stimulation program of deep Permian coals was commenced in the Moomba Field in 2007. Understandings of Permian source-rock reservoirs, the roles of the coal type and rank on sorption capacity and porosity, the influence of effective pressure and depth on coal permeability and the interrelation of coal fracture permeability with in-situ stress and mechanical stratigraphy has now advanced. The deep Permian coal fairway in the Patchawarra and Nappamerri Trough of the Cooper Basin has been defined and mapped using a generative potential approach within a comprehensive 3D basin model. Net coal thicknesses from log electro-facies for 879 wells has been combined with available well maturity, TOC, HI and kerogen kinetic data, and calibrated against corrected temperatures in a basin-wide Trinity retention model which incorporates 14 mapped regional horizons. Play fairways have been overlain with observations of in-situ stress direction and fracture orientations from 3D seismic curvature volumes, FMI data and stress states from Mechanical Earth Models (MEM). Within the basin, this approach has defined a P50 in-place resource of 14.6 TCF of gas and a P10 of 20.7 TCF of gas within the deep coals of the Permian Toolachee, Epsilon and Patchawarra Formations in Senex permits, of which 8-11 TCF is within the North Patchawarra Trough. MEM's have also demonstrated that deep coal seams are consistently in a normal stress state and therefore provide excellent scope for both propagating and constraining vertical fracture growth. Work is now underway to define further those areas, within the mapped resource parameters, which provide the best opportunity to site pilot lateral wells for multi-stage fracture stimulation within deep coals.

Java Field is located in the North West Java Basin that is one of the hydrocarbon prolific basins in Indonesia. The most of oil and gas in this area was produced from Jatibarang volcanic reservoir that consist of volcanic rock such as tuff, pyroclastic breccia, and lava andesite. In general, volcanic rocks have been ignored because a perceived lack of reservoir quality. Fractures were detected in the Jatibarang volcanic formation which enhanced porosity and permeability allowing hydrocarbon production. To exploit this type of reservoir to the fullest, comprehensive study must be done including determination of distribution and orientation of fault and fractures, possible migrations, and trap of hydrocarbon. Fractures identification and distribution modelling has been carried out in Java field with a combination of seismic interpretation by post-stack seismic geometrical attributes extraction, wireline log, imaging log and cores. A well log interpretation technique on the artificial neural network concept has been developed for evaluation of the volcanic rock reservoir and it was calibrated with imaging log and sidewall core data. Detailed petrophysical and petrographycal analysis have shown that the volcanic facies of Jatibarang formation is characterized by several types of tuff, andesite breccia, and andesite-basalt lava. The tuff facies is the best reservoir that has a multiporosity types with a range value of total porosity 6-19%, secondary porosity index value is 2-12% and average of fracture permeability value is ± 42,90 mD. The formation evaluation analysis of several productive well in Java field suggested that the distribution of productive well is mainly controlled by distribution of fractures beside by distribution of volcanic facies. The fractures in study area has three general orientation that is N-S, NNW-SSE and NE-SW trend strike of fractures. The all of fracture subsets were generated by polyphase tectonic event interpreted by N-S compressive stress during Mio-Pliocene and originally thought to be an extensional regime of the Cretaceous-Oligocene Meratus System that was rejuvenated during Pliocene. The N-S trend of conductive fractures is a potential open fractures that have ability to save and flow the hydrocarbon. Regarding the orientation of potential fractures, a horizontal well lateral from west to east is suggested for producing potential fractured volcanic reservoir in order to penetrate perpendicular to strike of productive fractures. This study can be analogue for all of unexplored volcanic reservoir, so this type of reservoir can be future target for hydrocarbon plays in Indonesia.

"Block X," located in offshore Sabah is operated by JX Nippon Oil & Gas Exploration (Deepwater Sabah) Limited., which had drilled several exploration wells and acquired extensive wireline and LWD information to evaluate the block for further exploration and future development. Drilling exploration wells in a deepwater environment can lead to drilling difficulties. For example, a very narrow safe mud weight window was encountered in the discovery Well X and subsequent drilling difficulties delayed the well delivery. In orderto minimize the drilling risk for upcoming prospects, detailed petrophysical, geological and geomechanical studies have been conducted based on extensive evaluation of wireline and LWD data. Determination of horizontal stress directions and magnitudes are an important part of building the 1D mechanical earth model, which allows optimizing perforation and completion design, and production planning. Knowledge of the stress directions also helps to optimize well trajectory design so that wellbore instability can be minimized. Several methods for identifying stress directions are available and investigated, including borehole breakout orientation and shear sonic anisotropy information. For complementing the existing drilling data (leak-off and formation integrity tests), the horizontal stress magnitudes are determined using the dipole radial profiles and the sonic anisotropy using acoustoelasticity theory. The variation in shear sonic slowness within the elastic region of the rock is compared to the stress distribution caused by the presence of the wellbore. The relationship between shear slowness (modulus) and stress is then established to provide the acoustoelastic coefficient and horizontal stress magnitudes (both minimum and maximum) are then determined. These results were used to reduce uncertainty in the state of stress, and used in optimizing the wellbore trajectories for future development wells. In the current study, besides conventional stress calibration data such as LOT/FIT and calliper information, advanced sonic information helped to calibrate further the stress profile, which resulted in a comprehensive understanding of the stress regime of the study area. These results are utilized to better design the mud weight program for the drilling of future Deepwater prospects in Block X.

The Surat Basin Coal Seam Gas (CSG) is maturing from exploration to production to meet sales targets for several Liquefied Natural Gas projects. This requires effective and predictable reservoir performance that is controlled by permeability, gas saturation and matching the well completion technique to the ground conditions. Permeability in coal has major dependence on in-situ stress and natural fractures, and these will have characteristics that vary from field scale to larger regional scale faults and folds. This study investigates the spatial and stratigraphic variability of stress and fracture orientation relative to measured permeability within the Walloon Subgroup (WSG) that hosts CSG resources within the Surat Basin. Open file wireline data from 33 vertical wells across the eastern part of the Surat Basin are used to calculate the in-situ stress orientation and fracture distributions within the WSG. Present day in-situ stress orientations were identified from the borehole breakout and drilling induced tensile fractures. Permeability data from 13 wells are compared using the in-situ stress and fracture data from image log interpretation. CSG reservoir permeability is, in general sensitive to the changes in effective stress and primary permeability is reduced exponentially with increasing effective vertical stress. However, this relationship does not always hold true. Permeability within the WSG is also affected by the angle between present day in-situ stress orientation and fracture or joint trends and fracture dip angle. Wells in the relatively simple structural areas with subtle faulting show higher permeability when the coal fracture trends are parallel and up to 40 degrees to the present day in-situ stress. Permeability is significantly less outside this range. Most of the high permeability zones tend to occur in the areas where there is significant rotation of in-situ stress from the regional mean stress orientation (commonly ENE – WSW). The observed stress rotation is attributed to the stress perturbations mainly from folds and faults within the Surat sedimentary succession, suggesting local structural influence on the permeability distribution within the WSG. Few analyses of permeability versus stress and fracture properties are in the public domain for the Surat Basin. This study illustrates the connection between different structural domains, stress and fractures in previously unidentified areas of oblique-slip faulting, in some cases reactivating and in others creating new features from basement through the Jurassic to Tertiary succession.

Drilling in the Cooper Basin faces challenges from the hostile stress environment, high-pressure and high-temperature conditions, and variations in rock properties with depth. The current understanding is that the Cooper Basin is under a highly deviatoric, strike-slip stress regime with significant stress contrasts between different lithologies. These conditions create challenges for drilling and well stimulation. A series of wells have been reviewed to understand the vertical and lateral stress changes in the Patchawarra Trough in the Northern Cooper Basin. The temperature anomaly at this location appears to be lower than in the Nappamerri Trough in the south. A different level of overpressure is also observed, and the formation pressure appears to vary depending on structural location. Shallow wells on the ridge appear to be near hydrostatic in the Permian sands, but overpressure is as high as 10.5-11 ppg on structures in the deeper part of the Patchawarra Trough. Rocks appear to be generally strong, with siltstones in the Permian section being only slightly weaker than sandstones. The stress anisotropy in the sandstone is large; the S Hmax /S hmin ratio is greater than 2. The stress anisotropy is considered to be the reason for preferential wellbore failure in sands instead of shaly siltstones. The stresses in interlayered thick coals tend to be near isotropic. It is also thought that the stress regime is not necessarily uniform with depth; the maximum horizontal stress decreases drastically at shallower depths, and the stress regime becomes normal faulting. The detailed geomechanical analysis shows that the drilling challenges faced in the deeper section are mainly caused by the thick coal sequences. Sandstones and siltstones are relatively strong, should not cause much wellbore instability, and are only expected to develop narrow breakouts. For hydraulic fracturing, the small stress contrast (similar minimum horizontal stress magnitudes) between sandstone and siltstone in the Permian formation would result in difficulty in confining the fracture in zone. Consequently, excessive height growth may cause the fracture to grow into highly fractured coals and may lead to early screen-outs. Detailed geomechanical modeling for a series of wells in the Patchawarra Trough has enabled a thorough understanding of variations in rock properties, pressure and stress in the area. Optimised drilling strategies for mud weight and mud properties were adopted for the drilling of vertical and horizontal wells. Accurate stress modelling also helped the optimisation of hydraulic fracture design to achieve successful fracture treatments for improved production.

The slip velocity of cuttings is a calculation of the settlement velocity of a particle in a stagnant fluid. In dynamics, the slip velocity is defined as the difference between the solid and the fluid velocities. If the cuttings velocities are low, the cuttings may not be transported efficiently to the surface, causing a variety of inefficiency issues. For example, they may accumulate at the bottom of the wellbore and get regrinded by the bit. Determination of the correct value of this parameter in vertical wells has been the concern of many investigations in the oil and gas industry. API RP 13D (2010) standard uses Walker and Mayes' study (1975) to calculate the slip velocity for vertical wells but as discussed below, this model does not show accurate results compared to other models. Moore's model (1974) provides better slip velocity calculation compared to Walker and Mayes' model. These methods are based on providing three sets of equations for laminar, transition, and turbulent to correlate Reynolds number to friction factor for an average value of sphericity for the drilling cuttings. This paper describes a new method to determine the cuttings slip velocity in vertical wells using neural networks. Artificial neural networks have been successfully implemented in many disciplines in the oil and gas industry. The interconnected network between the neurons provides a nonlinear approximation of the data to solve complex models. The "Reynolds number vs. friction factor" data at different particles' sphericity graphs has been used to determine the friction factor and then apply it to the Stokes slip velocity equation. Moore's model does not consider the sphericity of the particles because it uses a generic value for this figure, however, the new technique covers a wider range of the sphericity of particles from 0.125 to 1.0. In addition, this model gives higher accuracy compared to the afformentioned models.

Fractured basement reservoirs represent more than 20% of the world's oil and gas reserves. Because of their heterogeneity and complex, unconventional natures, the process of mapping the reservoir properties presents a monumental task. The identification of the high productivity zones in basement reservoirs presents a major challenge because of the drastic vertical and temporal variation in porosity and permeability. Reservoir characterization in terms of rock-forming minerals, multipore system analyses, hydrocarbon typing and quantification, and textural variations can be performed by combining quad-combo, elemental spectroscopy, and resistivity-imaging measurements, regardless of the conveyance technique, in an integrated workflow. Because fractures play a major role in hydrocarbon production, rapid reservoir decline, and undesirable fluids breakthrough, fracture description is crucial. Aside from conventional techniques to quantify matrix porosity and permeability, a workflow has been designed to provide additional unconventional techniques for multipore system analyses using high-resolution resistivity imaging. With one technique, the resistivity image is sculptured using an object-oriented filter that produces fracture density, aperture, and porosity. The other technique is based on a transformation of image conductivity to porosity that is classified into a matrix and secondary pores to estimate their contribution to permeability. The multipore system analysis is then used to determine the cementation exponent parameter needed for hydrocarbon quantification. Finally, critically stressed fractures are identified, using geomechanical analyses, to determine the production-contributing fractured zones. Although the technique/workflow used is relatively new and uncommon for data acquired while drilling, its results successfully met the objectives of the study with quality deliverables. This paper presents a basement reservoir characterization study with a discussion of the technologies used in the workflow, study results, conclusions, and recommendations for future work. Data used in this work were obtained from a well in Malacca, Malaysia.

Two methods are commonly used to produce window exits in multilateral wells. One implements premilled window technology, while the other involves steel casing milling. Steel casing milling generates steel cuttings that can be challenging to circulate to surface during wellbore cleanout and can hinder equipment in subsequent downhole operations. Premilled windows eliminate steel debris; however, they require that the main bore casing string be oriented. This paper describes an additional approach that does not create steel milling debris nor requires orientation of the casing string, which can result in significant time savings and risk reduction. This approach involves an all-aluminum casing exit joint (hereon referred to as ACE joint) coupled to a lower coupling with a latch profile in which service tools can be landed to perform junction construction. This new technology, including design rationale, development, installation procedures, subsequent testing, and field trial results are discussed within this document. The ACE joint was designed, manufactured, and deployed in a multiwell, TAML 5 multilateral field development containing bilateral and trilateral wells. To create the window exit, the ACE joint and latch coupling are made up to the main bore production casing and cemented in hole. An orientation tool is then run in hole (RIH) and latched into the joint latch coupling, obtaining coupling orientation. The whipstock and mill assembly is then configured at surface to the desired millout orientation, RIH, and latched into the ACE joint for subsequent milling operations. Lab testing has been performed to qualify the ACE joint for suitable milling performance, corrosion resistance, and drilling wear resistance; all with positive results. Field installations have also been successful, with bi and trilateral wells having laterals exceeding 2000 m in length being created without problem. The tests and field installations demonstrate the ACE joint is now a proven technology, confirming the window geometry post millout to be acceptable for lateral drilling and completion operations. This new approach to window millout technology represents an improvement to existing steel casing milling technology, providing a more suitable solution for removal of milling debris and a more simple installation process.

Wellbore instability remains a leading threat to oil operators as one of the main causes of non-productive time worldwide. As drilling technology advances, logging-while-drilling (LWD) measurements contribute valuable information to help identify instability problems in real time. One of the important measurements is the LWD ultrasonic caliper measurement, which makes it possible to identify borehole washout, breakout, keyseating, and spiral-hole conditions. Having this measurement enables diagnosis of wellbore stability problems while drilling without the need for an additional logging run, which is especially critical in an unstable wellbore. In the industry, breakout identification using image data can be a significantly user-dependent process and requires appropriate skills. The process is time consuming, and the final result can still be subjective. Further complication comes when considering a highly deviated well path or when the field stress regime is abnormal. As a consequence, drillers face difficulties using the LWD ultrasonic caliper data directly for wellbore stability diagnosis. We propose a methodology to overcome the limitation of conventional method and produce reliable quantitative breakout data to be used in real time, in an automated, systematic, and consistent way. An engineering-based workflow is introduced to distinguish zones of stress-induced breakouts from other borehole enlargement types with improved consistency and which can be easily translated into programming language. Instead of image data, this solution uses sector data to extract the borehole shape information using the cubic spline method. Six stringent LWD ultrasonic caliper-specific breakout criteria are introduced and used to identify breakout intervals from the borehole shape data. Adopting the idea from the World Stress Map (WSM) project, a data quality ranking was also performed using the result of the workflow. The quality ranking criteria (defined by WSM project) segregate the breakout results into five categories to infer the reliability of the breakout intervals identified. This quality ranking procedure will greatly improve the reliability of the output data in the workflow prior to quantitative usage. The result of the breakout identification is then used to determine the principle stress direction and the stress regime, using a 3D stress analysis method for deviated wells.

Newly acquired full azimuth 3D seismic in conjunction with modern azimuthal acquisition and processing, and a fresh review of the regional structural model, has enabled the identification of strike-slip faults with greater certainty. Strike-slip faults are often difficult to identify in traditionally processed seismic due to the lack of vertical displacement. The resulting improvement in structural detail in the geological models has provided a better match with well production, performance and reservoir connectivity in mature Cooper Basin fields. The structural interpretation is independently supported by Pressure Transient Analysis (PTA) and image log data in one of the fields. Field examples are used to demonstrate the observed relationship between strike-slip faulting and hydrodynamic connection. Pressure data supports that fields previously thought to be separate are demonstrated to be connected via strike-slip corridors. Therefore, hydrodynamic disconnect occurs across strike-slip faults. An observed relationship between underperforming wells and proximity to interpreted strike-slip faults is also discussed. The integrated approach combining new full azimuth 3D seismic data with regional structural concepts, well performance and dynamic behaviour has led to the identification of new development and appraisal opportunities in several mature fields. Application of this multidisciplinary approach, including the structural model, seismic interpretation and analysis of dynamic data is recommended for all fields throughout the Cooper Basin with suitable full azimuth seismic data. This process should be embedded in future field development plans.

Arrow Energy has engaged in drilling production Coal Bed Methane (CBM) wells in the Bowen Basin. As part of its field development strategy, varied styles of horizontal wells have been planned and executed along the coal targets of Moranbah Coal Measures (MCM). Some of the recently drilled multi-branch lateral and horizontal wells experienced different drilling challenges and production performance. Potential geomechanical issues such as borehole conditions and fines/solid production are directly related to wellbore stability during and post drilling. As part of Arrow subsurface modeling strategy, the project has embarked a detailed Geomechanics study in Moranbah Gas field. The main objectives were aiming to: (i) optimize the mud weight that is required to stabilize the borehole, (ii) understand how specific coal targets respond to the induced stress concentration around the wellbore during drilling and, (iii) capture the vertical and lateral mechanical heterogeneity within specific coal seams. This paper focuses on practical solutions to model the borehole stability, in particular of the uncertainties in the rock strength modeling and coal heterogeneity. This innovative workflow coupled with geostatistical approach of rock strength and insitu stress with depth-of-damage is first of its kind in CBM environment. Borehole collapse depth-of-damage (DoD) concept is then used to assess risk associated to the volume of yielded rock as a percent of borehole size. The higher the percentage of DoD, the higher the risk of producing excessive cavings. It provides more confidence in optimizing drilling mud weight for CBM horizontal wells by allowing a more scientifically-sound and practical solution to address rock failure mechanisms associated with borehole instability.

The Nappamerri Trough in the Cooper Basin has long been recognised as a potential unconventional resource play with both deep-basin ( Hillis et al. 2001 ) or basin-centred gas, and, more recently, as a potential shale gas target. However, initial attempts to fracture stimulate sandstones on conventional structural highs in and around the trough proved difficult. High treating pressures reached the limits of the well designs, and unsuccessful stimulation treatments resulted. A review of geomechanical information suggested that fracture complexity might have resulted from fractures initiating vertically and then twisting off to horizontal further into the reservoir ( Nelson et al. 2007 ). From 2010 to 2012, Beach Energy undertook a two-well exploration drilling program aimed at assessing the shale gas potential of the Nappamerri Trough and proving the presence of gas outside of structural closure. The wells were initially planned to gather base geological information from the core, but it was recognised that key fracture stimulation uncertainties could be addressed by these wells that would have significant benefit for future well design. With the knowledge gained from previous stimulation treatments, the wells were designed to incorporate Acid-soluble cement to improve the connection to the reservoir A fracture completion string—wellhead and pumping equipment suitable for higher treating pressures A surface tiltmeter monitoring array to ascertain whether treatments were twisting into the horizontal plane The two wells, Holdfast-1 and Encounter-1, were successfully stimulated with 13 different treatments. This paper summarises the interpretation of the treating pressure data and the tiltmeter responses. Through diligent pre-project planning, the observed treating pressures were manageable, although higher than pressure gradients in other published shales and tight-gas areas. Large near-wellbore (NWB) pressure losses in most intervals were successfully reduced to allow treatments to be placed using moderately low viscosity fluids. The interpretation of the tiltmeter array data indicated predominately vertical fracture development, which is a positive outcome for maximising stimulated reservoir volume (SRV) in future horizontal wells. However, the fracture orientation determined from the tiltmeters was not consistent with the anticipated maximum stress orientation from borehole logs and regional studies, and further investigation is required to resolve this difference.

A tight sandstone was fractured in a triaxial stress cell by injecting fraccing fluid. The specimen was then scanned with a micro-computed tomograph. From the resulting three-dimensional images the fracture morphology and orientation could be determined. Such measurements can be supportive in the development and validation of fracture propagation models. Such models can help optimizing gas and/or oil production from shales, tight sands, carbonates and coal beds.

One of the main challenges in the fractured basement exploration and development is the identification of proper well targets with minimized drilling risk. The estimation of fracture porosity and permeability distribution in reservoirs with low matrix porosity is also very challenging as the production relies mostly on the complex fracture network. The proposed method aims at identifying the potential flow-contributing fractures, modeling accurately the fracture density in the interwell space, and finally, building a robust and well-calibrated discrete fracture network (DFN) that is used to compute porosity and permeability properties. This holistic approach integrates the latest technologies for interpreting borehole images, identifying open fractures, computing fracture aperture, and generating a DFN. It also includes at each step qualitative and quantitative analyses to optimize the choice of 3D parameters: seismic attributes and estimations of fracture length, orientation and aperture distribution.

In coal seam gas (CSG), also known as coalbed methane (CBM), appraisal, the development potential of a play requires an understanding of the interrelationship between stress and permeability, critical elements in defining deliverability and hydraulic fracturing effectiveness. Unfortunately, the interdependency of these variables may not emerge until the post-treatment evaluation of a hydraulic fracturing treatment. Herein is an example from the Walloon Subgroup (WSG), Surat Basin, where regional data were used to target a small, localized, structural setting for CSG appraisal and subsequent hydraulic fracturing. Due to the rank of the WSG coals in this area, the cleat network was deemed to be immature and permeability is understood to be derived from exogenetic fracturing from external stresses acting on the coal, creating a unidirectional fracture network. The fractures are commonly constrained to brittle lithologies and truncate at bedding boundaries, while evidences exist of minor low angle faulting in non-reservoir lithologies. Eventually, the local stress regime was determined from the petrophysical log data, injection stress testing, and subsequent one-dimensional (1D) mechanical earth model (MEM). Ultimately, these data support the proposed reservoir and stress environment. We will show how data were acquired, evaluated and integrated to support the development of the 1D MEM and aided the interpretation of the hydraulic fracture treatment results. While localized, the results of this evaluation indicate a potential pitfall can exist in some CSG environments. This case illustrates a scenario where stress and dominant permeability axes can be properly aligned to maximize hydraulic fracture effectiveness, but where sub-optimal stress magnitudes prevent achieving the full benefit of the hydraulic fracturing process.

Abstract Borehole instability, in most of the cases, is a direct reflection of earth's in situ stress state. It is well known that the stress distribution around the wellbore induces deformation depending on many factors ranging from wellbore pressure history and rock strength to the trajectory orientation. A stress direction map is generated for the GoS from observations of borehole breakout detected in multi-arm-caliper logs and other log data base, viz., electrical Images and sonic logs. In vertical wells, the maximum tangential stress around borehole can produce breakouts and their orientation indicates the direction of minimum in situ horizontal stress (S h ). In the case of deviated wells, a stress-tensor diagram defines Sh direction with reasonable accuracy, provided wells cover wide range of deviation angle and azimuth The current study indicates that S h in GoS is aligned along two major trends. The main NNE - SSW trend, with average orientation of N10degE, exists in most of the region. The second trend is aligned NE - SW and observed locally at the central eastern and south-western part of GoS, with an average orientation of N50degE. Most studies of the structural and tectonic history of the GoS have identified two age significant orientations for this extensional rift. The early to middle Miocene rifting, responded to a S h direction of N55–60degE (rift-climax). The younger stress fields of the Late Miocene and Pliocene times rotated progressively counterclockwise to a N15-25degE direction that persisted into early-late Pleistocene time. The dominant in situ stress orientation trend, identified in this study, therefore, is mainly controlled by this younger stress field of the GoS rifting. In situ stress directions have strong impact in drilling high angle wells in GoS. Proper placement of well trajectory with respect to in situ stress reduces instability in drilling. The paper exhibits example of directional sensitivity of well trajectory and successful drilling campaign based on the developed stress map. Introduction Since the global power scenario changes with increasing demand for oil, more and more complex trajectory wells, highly deviated and horizontal, are being drilled in the areas with minimum knowledge with scanty or barely minimum previously drilled data. Enhancing the production to its maximum level is the reason, though the drilling uncertainty is being pushed to a limit that causes unexpected drilling problems resulting in high NPT; the expenditure goes beyond expectation involving multiple side tracks or abandonment of the well in worst case. In all the brown fields those are now being developed; the original data quality is very poor or inadequate to extract meaningful results that could be used to formulate a drilling program, one of this being the stress orientation of the area. This is a significant and most important input to forecast the drillability of the well. And in most of the cases the wells are being drilled without the proper knowledge of stress pattern of the area. The demand of an in-situ stress map, therefore, is extremely important while drilling a deviated high angle well. The situation becomes exceedingly critical if the drilling is being carried out in a tectonically active region involving multiple faults and variable degree of displacement of the adjoining structures. While mentioning a stress map we are mainly concerned about the directionality of the minimum stress across the region.

Abstract This paper investigates the effect of pore pressure change on the interaction of induced hydraulic fracture and natural fracture and the effect of natural fracture orientation. Warpiniski and Teufel's interaction criteria were adopted to evaluate the fracture propagation that would occur after an induced fracture intersects an existing natural fracture. A fully coupled finite element based model is used to simulate hydraulic fracture propagation in a poroelastic formation with existing natural fracture. In order to study the effect of pore pressure change on interaction zone, a poro-elastic solution for the stresses in the interaction zone has been used as a basis for fracture interaction criteria. From the results of this study, the following were observed when the induced fracture interacts with the natural fracture with changing pore pressure. At low angles of approach with low to high differential stress, the induced fracture is arrested by the natural fracture, then the natural fracture begins to open, diverting the fracturing fluid and preventing the induced fracture from crossing. At medium (60 deg and above) angles of approach fracture opening and crossing both was observed depending on the differential stress. In low differential stress opening occurred and in high differential stress (more than 600 psi) induced hydraulic fracture cross the natural fracture. At high angles of approach crossing occurred at all differential stresses. Pore pressure change does not have any direct impact on interaction type but it accelerates the reinnitiation pressure needed to cross the natural fracture. The pressure build up rate inside the natural fracture is influenced by the pore pressure change. This paper depicts that the effect of pore pressure change and the orientation of the natural fracture is of immense significance in hydraulic fracture propagation when it interacts with natural fracture. The study includes small to large natural fracture and low permeable formation.

Abstract Fault reactivation induced by excessive reservoir steam pressure in heavy oil fields is suspected as one of the possible perpetrators that caused steam eruption to the surface. This can lead to significant financial losses related to environment cleanup and curtailed oil production. A traditional approach to fault reactivation prediction provides a deterministic critical reservoir pressure without proper regard to the uncertainties in the model input parameters and the predicted results. A probability distribution of the fault reactivation maximum reservoir pressure provides a better means to calculate a risk weighted Expected Net Present Value for management to make better decisions on steam flooding and to anticipate potential consequences. In this study, a geomechanical model was established for the Batang Field, Central Sumatra, Indonesia. Using the geomechanical model, first, a fault seal analysis was performed and indicated that all faults were sealed in sands under initial stress and pore pressure conditions. Second, fault reactivation reservoir pressures for major faults in the field were predicted assuming a frictional sliding frictional coefficient of 0.5, which was derived using frictional faulting theory by a geomechanics services provider for the nearby Duri Field. Two scenarios were run in this case. One assumed a stress path coefficient of zero for horizontal stresses (decoupled); the other assumed a stress path coefficient of 0.4 (coupled). It was found that the coupling of stress and reservoir pressure provides a less conservative value of maximum reservoir pressure. Lastly, Monte Carlo simulations were run to consider the uncertainties of frictional sliding coefficient, and especially the stress path coefficient among the input parameters. It was found that the results from Monte Carlo simulations and deterministic approach were largely consistent but the resulting probability distribution from the Monte Carlo simulation approach provides significantly more information. Introduction Batang is a heavy oil field located in Central Sumatra, Indonesia, just north of the giant Duri Field (Figure 1). It is heavily faulted and compartmentalized (Figure 2). Currently the field has more than 60 wells producing from reservoirs at depths varying from about 100 ft to nearly 700 ft TVD. Huff-and-puff is being used on a single well basis to improve heavy oil production. The Batang asset team was considering whether to add pattern steam flooding to this field. Since steam eruption had occurred in the nearby Duri field, causing significant environmental problems and curtailed well production, the Batang team was interested in knowing how to properly operate the steam injection wells to reduce the chance of steam eruption to surface. According to the Duri field experiences, many of the steam eruptions were related to faults in addition to other factors such as poor cementing jobs [1]. In this study, it was also assumed that elevated reservoir pressure due to steam injection may cause a fault cutting through a reservoir to be reactivated, causing steam eruption to surface either directly along the fault plane or indirectly by first entering shallower low pressure reservoirs and then flowing through the gap between the cement sheath and formation. Using this assumption, a maximum reservoir pressure without reactivating a fault was predicted and provided to the Batang team for steam flooding design. To achieve that, first a geomechanical model needed to be established. Using the geomechanical model and the orientation of a specific fault, a normal stress and a shear stress on the fault plane were resolved [2]. Together with a Coulomb failure envelope, a critical reservoir pressure was calculated.