Kumar, Rajeev (Schlumberger) | Zacharia, Joseph (Schlumberger) | Guo Yu, Dai (Schlumberger) | Singh, Amit Kumar (Schlumberger) | Talreja, Rahul (Schlumberger) | Bandyopadhyay, Atanu (Schlumberger) | Subbiah, Surej Kumar (Schlumberger)
The unconventional reservoirs have emerged as major hydrocarbon prospects and optimum yield from these reservoirs is dependent on two key aspects, viz. well design and hydrofracturing wherein rock mechanics inputs play key role. The Sonic Measurements at borehole condition are used to compute the rock mechanical properties like Stress profile, Young's Modulus and Poisson's Ratio. Often, these are influenced by the anisotropy of layers and variations in well deviation for same formations. In one of the fields under review, the sonic compressional slowness varied from 8us/ft. to 20us/ft. at the target depth in shale layer in different wells drilled with varying deviation through same formations. This affected the values of stress profile, Young's Modulus and Poisson's Ratio resulting in inaccurate hydro-fracture design. At higher well deviation, breakouts were frequently observed and could not be explained on the basis of compressional slowness as it suggested faster and more competent formation. Current paper showcases case studies where hole condition improved in new wells with better hydro fracturing jobs considering effect of anisotropy in Geomechanics workflow. Sonic logs in deviated wells across shale layer were verticalized using estimated Thomson parameters considering different well path through same layer and core test results. Vertical and horizontal Young's Modulus and Poisson's Ratio were estimated for shale layers with better accuracy. The horizontal tectonic strain was constrained using radial profiles of the three shear moduli obtained from the Stoneley and cross-dipole sonic logs at depth intervals where stress induced anisotropy can be observed in permeable sandstone layer. A rock mechanics model was prepared by history matching borehole failures, drilling events and hydro-frac results in vertical and horizontal wells using updated rock properties. Geomechanical model with corrected sonic data helped to explain the breakouts in shale layer at 60deg-85deg well deviation where the original sonic basic data suggested faster and more competent formation with slight variation in stress profile among shale-sand layer. Considering shear failure, the mud weight to maintain good hole conditions at 80deg should be 0.6ppg-0.8ppg higher than that being used in offset vertical wells. Estimated closure pressure and breakdown pressure showed good match with frac results in deviated wells using new workflow. There was difference of .03psi/ft-0.07psi/ft. in shale layers using this new workflow which helped to explain frac height and containment during pressure history match. This paper elucidates the methodology that provides a reliable and accurate rock mechanics characterization to be used for well engineering applications. The study facilitates in safely and successfully drilling wells with lesser drilling issues and optimized frac stages.
Subbiah, Surej Kumar (Schlumberger) | Povstyanova, Magdalena (Schlumberger) | Egawa, Shimpei (ADOC) | Kokubo, Shinichi (JX Nippon Oil & Gas Exploration Corporation) | Yahata, Kazuhiro (JX Nippon Oil & Gas Exploration Corporation) | Okuzawa, Takeru (ADOC) | Vantala, Aurifullah (ADNOC) | Tan, Chee Phuat (Schlumberger) | Nasreldin, Gaisoni (Schlumberger) | Martin, Joel Wesley (Schlumberger) | Husien, Mohammad (Schlumberger) | Rajaiah, Nantha Kumar (Schlumberger)
In a recently drilled deviated well in an offshore field in UAE, severe cavings have been produced which led to difficulty in tripping out and stuck pipe events. A comprehensive study has been conducted to understand the chemical and mechanical behavior of the shales in the overburden.
This paper focuses on how we approached optimization of drilling design and practices where well construction was concerned (namely casing design and mud formulation). This approach minimized mechanical and time-dependent chemical instabilities in the Fiqa, Laffan and Nahr-Umr shales. After the initial implementation of the optimized drilling practices, a complex multi-discipline study including time-dependent shale stability analysis provided recommendations for the problematic shales should they be kept open for long durations (to reach section TD, log and case).
The time-dependent shale stability analysis included three major phases. The first phase was conducted based on the data for several selected existing wells. This phase resulted in obtaining so called field-based mud design criteria together with customized laboratory measurements. The second phase is to conduct a comprehensive geomechanical model to understand the mechanical behavior of the formations. In this study both 1D and 3D geomechanical models have been constructed honoring the anisotropic nature of the shales. The third phase was focused on selecting best mud system and optimizing the mud designs to prevent/minimize both mechanical and time-dependent chemical instabilities for shales layers with long exposure time.
The problematic shales were penetrated at relatively high angles, requiring high mud weights and therefore leading to relatively high overbalance pressures which can cause high pore pressure increase in the shales with time. However, it is still feasible to select an optimum drilling fluid design for the desired mud system by optimizing salinity for the required high mud weights to avoid time-dependent instability. The Nahr-Umr shale, in general, was deemed to be more susceptible to mechanical and time-dependent chemical instabilities due to higher required mud weights and overbalance pressures.
The Fiqa, Laffan and Nahr-Umr shale formations could be drilled using the recommended mud weights together with best mud formulations to avoid both mechanical and chemical time-dependent wellbore instability problems in the planned wells. The outcome of the study helps in keeping the shales open for longer period in highly deviated wells without any wellbore instability before casing runs.
The workflow utilized for the shale stability analysis for Fiqa, Laffan and Nahr-Umr included an approach innovative for UAE to understand mechanical and chemical (osmosis-related) behavior of the problematic shales to develop recommendations for cases when the shales needed be kept open for long durations.
Dasgupta, Suvodip (Schlumberger) | Raina, Ishan (Schlumberger) | Povstyanova, Magdalena (ADNOC E&P) | Laer, Pierre Van (ADNOC E&P) | Baig, Muhammad Zeeshan (ADNOC E&P) | Casson, Neil (ADNOC E&P) | Marzooqi, Hassan Al (ADNOC E&P) | Suwaidi, Salama Jumaa Al (ADNOC E&P) | Ali, Humair (Schlumberger) | Subbiah, Surej Kumar (Schlumberger) | Mello, Ashish D' (Schlumberger)
Talreja, Rahul (Members) | Kumar, Rajeev Ranjan (Members) | Subbiah, Surej Kumar (Members) | Murthy, V. M. S. R. (Department of Mining Engineering, Indian School of Mines Dhanbad) | Munshi, Shri B. (Department of Mining Engineering, Indian School of Mines Dhanbad)
One of the main rock mechanical properties required for all design applications is fracture toughness. The fracture toughness values are helpful for simulation of hydraulic-fracture propagation, drill energy requirements, drilling rate prediction, wear rate etc. In this study fracture toughness testing of rock with core based specimens was performed with an emphasis on chevron shaped notches specimen. The same rock sample were then subjected to different small scale rock mechanics laboratory tests to determine various mechanical properties like drilling rate index (DRI), compressional slowness, uniaxial compressive strength and tensile strength of the rock. An outline of the methods used is given in the paper. Based on the data obtain from these tests, correlations are established using regression analysis between fracture toughness values and determined rock mechanical properties. This study provides empirical correlations, which will be helpful in estimation of fracture toughness for sandstones and siltstone.
Gurmen, M. Nihat (Schlumberger) | Fredd, Christopher N. (Schlumberger) | Batmaz, Taner (Schlumberger) | Kurniadi, Stevanus dwi (Schlumberger) | Zeidi, Omar Al (Schlumberger) | Kanneganti, Kousic (Schlumberger) | Nasreldin, Gaisoni (Schlumberger) | Khan, Safdar (Schlumberger) | Tineo, Roberto (Schlumberger) | Subbiah, Surej Kumar (Schlumberger)
Innovation and advances in technology have enabled the industry to exploit lower-permeability and more-complex reservoirs around the world. Approaches such as horizontal drilling and multistage hydraulic fracturing have expanded the envelope for economic viability. However, along with enabling economic viability in new basins come new challenges. Such is the case in the Middle East and North Africa regions, where basin complexity arising from tectonics and complicated geology is creating a difficult geomechanical environment that is impacting the success of hydraulic fracturing operations in tight reservoirs and unconventional resources. The impact has been significant, including the inability to initiate hydraulic fractures, fracture placement issues, fracture connectivity limitations, casing deformation problems, and production impairment challenges.
Completion quality (CQ) relates to the ability to generate the required hydraulic fracture surface area and sustained fracture conductivity that will permit hydrocarbon flow from the formation to the wellbore at economic rates. It groups parameters related to the in-situ state of stress (including ordering, orientation, and amount of anisotropy), elastic properties (e.g., Young's modulus and Poisson's ratio), pore pressure, and the presence of natural fractures and faults. Collectively, this group of properties impacts many key aspects determining the geometry of the fracture, particularly lateral extent and vertical containment. Heterogeneity in CQ often necessitates customizing well placement and completion designs based on regional or local variability. This customization is particularly important to address local heterogeneity in the stress state and horizontal features in the rock fabric (e.g., laminations, weak interfaces, and natural fractures) that have been identified as key contributors impacting the success of hydraulic fracture treatments.
Given the observation that a wide range of CQ heterogeneity was creating a complex impact on hydraulic fracture performance, CQ classes were introduced to characterize the risk of developing hydraulic fracture complexity in the horizontal plane and the associated impact on well delivery and production performance. They indicate the expected hydraulic fracture geometry at a given location and are analyzed in the context of a wellbore trajectory in a given local stress state. CQ class 1 denotes locations where conditions lead to the formation of vertical hydraulic fractures, CQ class 2 denotes locations where conditions lead to the formation of a T-shaped or twist/turn in the hydraulic fracture, and CQ class 3 denotes locations where conditions lead to the formation of hydraulic fracture with predominantly horizontal components. Wellbore measurements indicate that these CQ classes can vary along the length of the wellbore, and 3D geomechanical studies indicate that they can vary spatially across a basin. By understanding this variability in CQ class, well placement and completion design strategies can be optimized to overcome reservoirheterogeneity and enable successful hydraulic fracturing in more challenging environments.
This paper introduces the novel concept of CQ class to characterize basin complexity; shows examples of CQ class variability from around the world; and provides integrated drilling, completion, and stimulation strategies to mitigate the risks to hydraulic fracturing operations and optimize production performance.
Kuwait Oil Company (KOC) was planning further development of the Sabriyah (SA) and Raudhatain (RA) fields by drilling a number of horizontal wells. Both fields presented considerable challenges that included, among other factors, drilling through several problematic shales. The major drilling issues experienced in the shales comprised of tight spots, packs-off, etc. To optimize the drilling process and minimize the risks while penetrating the shales, a decision to conduct a geomechanical study was made. The geomechanical study was focused not only on improvement of the mud weight program (mechanical wellbore stability analysis was conducted) but also on drilling fluid optimization as well.
The drilling fluid optimization analysis was carried out in order to evaluate the potential time-dependent wellbore instability mechanism(s) in the Ahmadi, Wara and Middle Burgan shale formations in the two fields, to define salt concentration for nominated mud types, and to develop solution and strategy to mitigate and/or manage the wellbore instability problems.
Based on the time-dependent shale stability analysis, recommendations were made for drilling the Ahmadi, Wara and Middle Burgan shale formations for water-based mud (WBM) and oil-based mud (OBM). Mud salinities were provided for several combinations of designed mud weight and evaluated breakout mud weight.
The following conclusions were drawn based on the geomechanical study: Water activity of the Ahmadi, Wara and Middle Burgan shale formations was moderately high. Hence, it was feasible to select an optimum drilling fluid design (whereby the mud pressure penetration was fully counteracted by the chemical potential mechanism) for WBM and OBM for the shale formations, even though overbalance pressure in the formations was relatively high. The Ahmadi, Wara and Middle Burgan shale formations could have been drilled using the designed mud weight programme and salinities for the two mud types without significant time-dependent wellbore instability problems in the analyzed planned wells. If the recommendations on mud weight and/or salinities were not fully followed, the shale formations could deteriorate with time due to either mud pressure penetration mechanism being not fully counteracted by chemical potential mechanism or over-dehydration. Increase in drag that could indicate formation deterioration should be established based on drilling parameters and rig capabilities.
Water activity of the Ahmadi, Wara and Middle Burgan shale formations was moderately high. Hence, it was feasible to select an optimum drilling fluid design (whereby the mud pressure penetration was fully counteracted by the chemical potential mechanism) for WBM and OBM for the shale formations, even though overbalance pressure in the formations was relatively high. The Ahmadi, Wara and Middle Burgan shale formations could have been drilled using the designed mud weight programme and salinities for the two mud types without significant time-dependent wellbore instability problems in the analyzed planned wells.
If the recommendations on mud weight and/or salinities were not fully followed, the shale formations could deteriorate with time due to either mud pressure penetration mechanism being not fully counteracted by chemical potential mechanism or over-dehydration. Increase in drag that could indicate formation deterioration should be established based on drilling parameters and rig capabilities.
The main objective of this paper to is to discuss the recent finding on the formation anisotropy and lateral heterogeneity in the different hydrocarbon fields of onshore Abu Dhabi. The study was focused on Thamama and Wasia groups, mainly related anisotropy and spatial heterogeneity of the geomechanical poperties for reservoir characterization. This would have an impact on the stress variation and the definition of potential "sweet spots" for well placement optimization and identification of suitable completion methods.
The 1D Mechanical Earth model (MEM) is a description and quantification of rock elastic and strength properties, in-situ stresses and pore pressure as a function of depth, referenced to a stratigraphic column. The available wireline logs of several existing wells, including the compressional and shear slowness, stonely, bulk density, and gamma ray were used to compute log-derived elastic parameters, strength properties and stress components. Rock mechanics laboratory core plug tests were performed to calibrate the log-derived mechanical properties. Anisotropic modelling was applied to understand the anisotropy in elastic properties and horizontal stresses.
Integrating the 1D-MEMs indicate that Onshore Abu Dhabi Geomechanical properties (elastic and strength) and in-situ stresses vary laterally and vertically. Further, several mechanical layering and horizontal stress anisotropy can be identified. These results imply that the Wasia and Thamama reservoirs are susceptible to different fracturing mechanisms. Hence different fracture and faults sets can be predicted within the highly anisotropic deformation zones.
These findings significantly impact the exploration play concepts, where lateral variations are anticipated. This also applied to the production and development, where the stress barriers control the stimulation and completion strategies.
An innovative approach for sand management with down-hole validation.
Sand production caused the abandonment of two production wells out of four on a gas field located in the Netherlands sector of the North Sea. The two abandoned wells accounted for 75% of total gas production on the field. This paper describes how geomechanics were applied to develop a screenless completion design to re-establish economic sand-free production rates for the field.
A geomechanics study of the reservoir sections of the abandoned wells examined the mechanical properties, including rock strength and plasticity, as well as the state of stress acting on the producing sections. The study predicted the sanding history of both wells accurately. Modelling indicated that a thin sand layer with low rock strength was the main contributor to the overall sand production. This was later validated with a Downhole Sand Detector Tool. The modeling also indicated that sand production was likely from other, stronger sections of the reservoir as the field continued to deplete
Once a validated prediction of sand failure had been constructed for the reservoir, the study investigated improvements to the well design that would give both economic productions rates and sand-free production for the lifetime of the field. In addition to considering geomechanical properties, the study investigated the geometry of the completion to find the most stable orientations for the wellbore and the perforations.
After an economic feasibility study, one of the abandoned wells was sidetracked along the optimally selected trajectory and perforated with oriented guns, isolating identified weak zones. The field has been producing since this remedial work without any sand production and the missed production has been recovered.
Technology Update - No abstract available.
Variation of gas demand yearly, weekly, at different time in a day and seasonally is the main driving factor for gas storage. Ideally the gas needs to be stored at the consumption points and the demand fluctuations need to be met by supply. Thus the underground gas storage operators need to maximize the storage capacity and minimize the cost of storage. Furthermore the operations need to be safe during the injection and production cycles.
During underground gas storage the reservoir is exposed to large range of pressure changes i.e. injection and production cycle. The stress state acting on the reservoir rock during this cycle is very high. In addition, the rate at which gas is injected and produced can subject the reservoir rock in the near wellbore region to large stresses. Both the change in stress due to changes in the reservoir pressure and changes in stress due to injection and production rate can be sufficient to fail the rock in this near wellbore region and cause sand production. Any sand production is likely to damage wellbore and surface equipment, and ultimately may render the gas storage operation unviable.
An understanding of the state of stress in the reservoir created by these gas storage operations is critical to avoid unwanted sand production. A geomechanical review of the potential for sand production in the Haidach Underground Storage Reservoir, Austria, illustrates the steps necessary to determine the stress state that will cause formation deformation and probable sand production. The study assists the selection of stable zones for perforating wells and sets operational limits for the gas flow to and from the wells
In the year 2004 Austria has imported 5840 106 Nm³, domestically produced 1963 106 Nm³ and consumed 8563 106 Nm³. The difference covers own use for domestic production and movements from / into storage inventories. RAG with its centre of E&P activities in the federal provinces of Upper Austria and Salzburg, both located near the German border forecasts an additional demand for storage in the gas markets of Central Europe. For this reason a new storage is under construction in the depleted gas field of Haidach. The available gas volume in 2007 will figure at 1200 106 Nm³ and 12 106 Nm³/d and will be increased to 2400 106 Nm³ and 24 106 Nm³/d in 2011. [WGC Report, 23rd World Gas Conference Amsterdam 2006] In order to assist the operation a study has been conducted to select the best completion option for Haidach UGS as part of
field development plan. Using a wide range of input data including seismic, wireline logs, drilling reports, mechanical core tests, geological and petrophysical interpretations, a detailed Mechanical Earth Model (MEM) was developed. The MEM forms the basis for planning stable wellbores and completions. Rock mechanical testing of core samples was performed to calibrate correlations made between log data and rock strength parameters. Using the MEM sanding propensity analysis was conducted using proprietary software. A formation completion selection tool was also used to identify potential completion options.