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Abstract When hydrocarbons are produced from a subsurface reservoir, pore pressure in the reservoir is reduced. This reduction (termed depletion) causes a redistribution of stress in the reservoir and surrounding rocks, leading to a variety of potential issues such as compaction and subsidence, fault reactivation and other forms of strain localization. It generally also leads to a reduction in the minimum horizontal stress (Sh) and therefore to a potential reduction in the fracture gradient (FG) in the depleted interval. The reduction in FG can be one of the most notable challenges when attempting to drill and complete new wells and is the focus of this paper. The level of depletion at which the reduced FG becomes an operational issue is a function of the geomechanical properties of the reservoir and surrounding rocks. It is also a function the effectiveness of so called “wellbore strengthening” techniques which aim to locally increase the FG by the addition of an appropriately sized concentration of lost circulation material (LCM). Within BP, reservoirs with depleted sand drilling challenges range from just a few hundred psi of depletion (for example in deep water Angola fields with shallow reservoirs) to several thousand psi (in deeper reservoirs as in the Gulf of Mexico) and in some cases to 10,000 psi or more of depletion in certain High Pressure/High Temperature settings. Quantifying the FG of the depleted interval and the effectiveness of wellbore strengthening techniques is key to field development planning and safe drilling operations. For a safe and successful development, several issues need to be considered. These include the variation of original (prior to depletion) FG across a field (where experience has shown that traditional 1-D models are inadequate for the complex structures drilled today), the change of FG with depletion (is the “Stress Path” linear and uniform across the field, or is structure and potential stress arching important?), and by how much we can increase the near-wellbore FG using wellbore strengthening techniques such as StressCage. In this paper, we present an integrated workflow undertaken to mitigate the risks of drilling depleted sands. Field examples are used to demonstrate the utilization of multiple sources of information including drilling data, rock mechanics, and stress analysis, along with the size distribution and concentration of particulate materials in the mud to achieve an optimum solution.
ABSTRACT: The Mars field began production in the mid-1990s, and a wealth of direct and indirect stress measurements have been accumulated through drilling and completion operations over the years. Typical data collected over the years include casing shoe formation integrity tests, leak-off tests, lost circulation events while drilling, mini-frac during completions, and step-rate tests in the producing reservoirs. While this traditional dataset provides some basic insights into stress characterization around the basin, extrapolating these data for more specific operations can be challenging due to the complexity from various level of activities across the 70+ stacked sands. Some of the challenges in utilizing the traditional dataset includes defining waterflood injection limits and in managing drilling margin through severely depleted zones. To aid better decision making, some novel measurement programs have been conducted over the last few years such as cased-hole microfracture tests during abandonment of wellbores. More recently, a series of modified open-hole extended leak-off tests were conducted to define the impacts of drilling mud on fracture pressures where both depleted reservoir sands and bounding shales were exposed. These newly acquired data along with our traditional dataset provided the Mars asset new insights into the impacts of various operation decisions on fracturing potentials both in the caprock and through depleted reservoirs. This dataset also unlocked new reserves and opportunities within the basin. In this paper, we provide an overview on the various components of this unique in-situ stress measurement program that has significantly impacted both our development and operating philosophy at Mars.
The Mars basin consists of over twenty major stacked reservoirs in the Deepwater Gulf of Mexico and has been on production since 1996. Despite waterflood commencing in 2005, struggles in achieving expected injection rate and well life from the early injectors has caused depletion in excess of 5,000 psi in several reservoirs. To continue developing some of the basin’s deeper and larger reservoirs, future wells must be drilled through many of these shallow depleted sands. If one of these reservoirs is overly depleted and can no longer be drilled safely, significant volumes from the deeper reservoirs could be lost. An integrated team consisting of subsurface specialists (petrophysicist, geologist, geomechanist, reservoir engineer, production technologist), drilling engineers, and economists have completed a field drillability study. This study evaluated the drilling margin, which is the difference between the expected pore pressure (PP) and estimated depleted fracture gradient (FG), for more than 70 proposed wells in the field development plan (FDP). Based on Shell’s understanding of depleted fracture gradients at the time, several planned wells were deemed un-drillable and many more would become un-drillable if reservoirs continued to deplete with no pressure maintenance. Without a successful waterflood program or depleted drilling program in place, the Mars asset opted to curtail production from specific reservoirs, which amounted to over 10,000 barrels of oil per day. Adjustments to the FDP to protect access to the deeper resources also caused a decrease in value of the asset. Meanwhile, the value of the waterflood program also diminished because of the need to continue replacing water injector wells, further delaying the blowdown. The asset recognized that the success of a challenging depleted drilling program along with an efficient waterflood program requires a thorough understanding of the subsurface stresses.
Rana, Rohit (Independent Geomechanics and Pore Pressure Consultant) | Hansen, Kirk S. (Shell India Markets Private Limited) | Kandpal, Jyoti (Shell India Markets Private Limited) | Kumar, Rajan (Shell India Markets Private Limited) | Schutjens, Peter (Shell India Markets Private Limited) | Muro, Leytzher (Shell India Markets Private Limited) | Rees, Daniel (Brunei Shell Petroleum Co Sdn Bhd) | Latief, Agus I. (Brunei Shell Petroleum Co Sdn Bhd)
Abstract Knowledge of the in-situ stress state and how it varies with reservoir depletion is important for the design and execution of in-fill drilling. This paper highlights the key geomechanical aspects and their usage in planning of wells through severely depleted (up to 25 MPa) and overpressured zones within a very short depth interval (few 10s of m), in an onshore gas field in Brunei. With focus shifting from oil to deep-gas development, drilling complications include risks of wellbore instability, excessive mud loss and internal blowouts, as well as differential sticking in the depleted reservoirs. Moreover, fracturing of the depleted sands while drilling infill wells carries the risk of jeopardizing production at nearby producing wells because of locally altered flow paths. The risks were evaluated by application of empirical and analytical geomechanical models of stress changes with depletion, and by elasto-plastic finite element models of borehole instability (collapse) due to shear failure. Our results show that for an average depletion rate of 1 MPa/year, the drilling window (difference between maximum allowable mud weight controlled by fracture pressure and minimum mud weight controlled by formation pore pressure or borehole collapse pressure, whichever is greater) is likely to remain open for the coming 12 years. Minifrac or extended leak-off tests at different stages of field development should be taken to monitor stress changes within the reservoirs and provide updates for calibration of the geomechanical model. Next to showing the geomechanical model results and their application to drilling, we demonstrate the refinement of pore pressure/fracture pressure predictions (i.e. narrowing down the uncertainty in the drilling window) for mature fields where producing "from the bottom up" has not been feasible. We also indicate how risks associated with drilling through depleted/undepleted reservoir sequences in a single hole section can be managed to as low as reasonably practicable with the help of geomechanical input. These results "open the door" for accessing deeper potential pay zones by drilling through severely depleted formations.
Fang, Zhi (Brunei Shell Petroleum Co Sdn Bhd) | Zamikhan, Norshah (Brunei Shell Petroleum Co Sdn Bhd) | Tarang, Ravie-Tajit (Brunei Shell Petroleum Co Sdn Bhd) | On, Chee Khong (Brunei Shell Petroleum Co Sdn Bhd) | Huver, Pieter Hendricus (Brunei Shell Petroleum Co Sdn Bhd)
Abstract Fracture gradient (FG) of wellbores is the function of not only stresses, formation pressure and rock mechanical properties but also well trajectories. An accurate FG prediction is critical for safe well drilling. However, the existing methods do not account for the trajectory effects. An integrated geomechanical approach has been developed to more accurately predict the FG of wellbores subject to various trajectories. The approach deploys the Kirsch equations and takes into account the effects of formation pressure variations on stresses. It further integrates the elaborated individual procedures for deriving the geomechanical input parameters from regional field data to form a FG model. After verifying the losses test and offset well drilling data with necessary modifications, the calibrated FG model is then able to more accurately predict the fracture initiation pressure (FIP) of wellbores to mitigate the drilling losses for not only vertical but also deviated wellbores by guiding the equivalent circulation density (ECD) management. The integrated geomechanical approach has been applied to the planning and drilling of more than 30 new wells at Brunei Shell Petroleum (BSP). It has significantly mitigated the drilling losses for the challenging wells of a field redevelopment project in which about 50 deviated wells were expecting narrow drilling windows due to penetrating heavily depleted reservoirs. In another drilling campaign, it saved the sidetrack of a lost hole section by revising the trajectory as instructed by the FIP predictions. The integrated geomechanical approach is an algorithm that can effectively mitigate drilling losses by accurately predicting the FG for any arbitrary wellbores.
Description Appraisal wells prior to field development provide the only opportunity to gather data required to maximize production through completions and reduce costs through optimized operations. Full understanding of the stress state in the earth, anisotropic rock mechanics and pore pressure is essential for safe, efficient drilling of the deviated development wells and production to their full potential. Understanding uncertainties in these parameters affects the economic production of these assets. A recent appraisal well in Hess's Bergading Field, drilled for a shallow sand, provided the opportunity to use it as a laboratory for future development. Full waveform sonic data, wellbore images, stress testing and full cores were gathered. Continuous estimates of anisotropic rock mechanical properties were compared and calibrated with core The 3 dimensional shear moduli were measured and continuous magnitudes of reservoir horizontal stress were obtained. Although the borehole itself was close to circular showing no break-out, larger than expected horizontal stresses were observed and the mini-frac failed to achieve breakdown at a pressure of 4500psi at 4000ft. State of the art sonic measurements providing shear radial-profiling from the sand-face into the far-field allowed direct derivation of horizontal stress magnitudes in the sand. These measurements also predicted a higher formation breakdown pressure than was applied in the mini-frac test. Application Well-bore stability, sanding and perforating all depend for their effective utilization on an understanding of the rock mechanics and state of stress of the material around the borehole. The horizontal stress field and the rock strength define the failure modes and predict stability and sanding behaviour in deviated wells planned for field development. Results The horizontal stresses from the sonic measurements were used to generate a revised safe drilling window for mud-weight. Subsequent core test results were able to describe plastic vs. elastic behaviour in the near-wellbore region to predict failure modes. Perforation recommendations and sanding predictions were also produced Significance Results are significant because they speak to the underlying geology of the basin, the behaviour of individual boreholes within that setting and the optimization of strategies in well, perforation and completion design, thus reducing cost and maximizing production