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ABSTRACT: Many wells in the Deepwater Gulf of Mexico are drilled through highly depleted reservoirs. Challenges executing wells in these narrow drilling margin environments include – 1) impairment of drilling operations due to mud losses while drilling & 2) inadequate cement coverage across stacked depleted reservoirs requiring remediation work. Industry experience demonstrates that events related to losses can be mitigated through proactive implementation of wellbore strengthening (WBS) techniques. This paper discusses recent Shell applications of WBS with a focus on Deepwater Gulf of Mexico (GoM). We discuss the design and operationalization of these methods to minimize non-productive time (NPT). In our first example well, lost circulation material (LCM) was added to the drilling mud and a static squeeze was performed across highly depleted sands (ΔP ∼4500 psi). In contrast to previous wells with similar depletion, this well was drilled and cemented with relatively lower NPT. In other wells drilled through reservoir with similar depletion levels, only carefully sized background LCM was used. The results of these wells have been integrated with industry learnings and Shell multidisciplinary expertise to devise a recommended operational workflow for WBS application in the GoM.
Loss of drilling mud into induced or natural fractures is a source of NPT in the GoM. Studies show around 12% of the total NPT associated with drilling shelf gas wells in the GoM is credited to lost circulation events (Dodson, 2004). The lost circulation events are only constrained to drilling operations, but may also occur during running and cementing casing. Comparison done by British Petroleum for their GoM wells indicated that modeled cementing ECDs were often 0.2 – 0.5 ppg higher than the drilling ECDs (Majidi, et al., 2018). This may cause losses during cementing, resulting in poor zonal isolation between stacked reservoir, that may require squeezing additional cement. Other associated cost implications due to lost circulation events include the potential to sidetrack the well and running additional casing strings.
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.
The field is operated by Shell Malaysia and is the company's first deepwater asset in Malaysia. The first phase development was delivered by 2014. The planned Phase 2 campaign aims to maintain the oil production plateau. One of the campaign objectives is to produce from the deepest untapped reservoir. However, due to the depleted nature of all 3 reservoirs located above the untapped reservoir, there is a need to drill through these depleted intervals with extremely narrow drilling margin window (less than 0.5 ppg). An added complexity is the location of the reservoir which is situated directly below the hydrates bulge of the field. Due to hyrdrates disassociation concerns by producing through the hyrdate layer, the current surface location of the well is situated 3km away from the reservoir adding ERD drilling challenges to an already complex well. Lastly, geomechanical analysis indicate that the relatively high mud weight required to maintain borehole stability in the shale intervals results in a negative margin scenario between the Stabor mudweight and the fracture gradient. To address the challenges of this well, an integrated approach between various disciplines such as Wells, Subsurface, Well, Reservois and Facilities Management (WRFM), and Subsea is a critical success factor. Every discipline plays an integral role to increase the probability of success. Some of the project enablers ongoing efforts include: Geomechanic assessment on representative fracture gradient with lower depletion constant to widen the drilling window, leveraging the learning from UK and Gulf of Mexico (GOM) experience and borehole stability subject matter expert (SME) network. Wells assessment on technologies in Managed Pressure Drilling and stress caging with optimisation in well trajectory and casing design. Collaboration between Subsea, Subsurface and Wells on geohazard assessment to move subsea top-hole location to avoid potential geohazards that adds complexity to the well. The project is going through the detailed design phase until the end of 2018. The results of the Detailed design phase will be shared during the conference.
The ultra-deepwater fields in the Gulf of Mexico are among the largest producers discovered to date. However, the reservoirs are interbedded with highly depleted zones, with pressure differentials up to 11,000 psi. The development, testing, and application of wellbore stability modeling software that accurately characterizes fractures, determines the optimal lost circulation material (LCM) blend, and delivers reliable wellbore strengthening results in the problematic production zones are discussed.
Wellbore strengthening literature focuses on three fundamental areas: stress caging, fracture–closure stress, and resistance to fracture propagation. Aspects of these approaches were incorporated into a new modeling solution that was calibrated using historical data from nine offset wells. The modeled fracture width predictions were used to design lost circulation material (LCM) treatments with specific particle size distribution values. Each formulation underwent particle-plugging testing in the laboratory, followed by flow loop testing of the best performers for compatibility with downhole tools. The highly interactive process, which currently continues, resulted in successful field applications in similarly complex wells.
The new model allowed drilling personnel to identify the parameters most likely to induce fractures. Equivalent circulating density (ECD) had the most impact, followed by minimum horizontal stress, Young’s modulus, fracture length, and Poisson’s ratio. Using modeling outputs, LCM blends were engineered to plug fracture widths ranging from 1,500 to 2,000 microns, significantly wider than previous estimates. Field results indicated that an "extended" ECD margin could be obtained for severely depleted formations. The optimized LCM treatments were applied on two wells with narrow pore pressure/fracture gradient margins and on one well with a severely depleted reservoir (4,600 psi). All three were drilled with zero losses. On a fourth well, the modeled treatment was applied to the leak-off test at the 16-in casing shoe above the production zone. The operator expected a 0.4 to 0.5 lbm/gal increase at best; the actual increase was more than 1.0 lbm/gal. After this interval was drilled, a 14 in liner was set and cemented with zero losses. Such an increase had not been possible on offsets previously. Based on these successes under similar conditions, the operator is currently implementing the model to design wells with extreme depletion to be drilled during 2020.
Decades of deepwater experience have yielded numerous best practices for drilling in narrow margins and depleted zones. However, many wells still cannot be drilled without an assurance of effective wellbore strengthening. By removing the limitations of other wellbore strengthening approaches, the field-proven geomechanics modeling software presented in this paper creates a new standard for lost circulation prevention in depleted sands with 8,000 to 11,000 psi differentials.
Abstract Drilling depleted or weak zones has always been a challenge, but with the aging of fields and the desire to drill to deeper in-field plays, the situation is becoming more exacerbated. The typical problems associated with drilling these types of intervals are lost circulation, stuck pipe and wellbore instability resulting in significant and expensive non-productive time (NPT) and costly remediation operations. Conventional lost circulation remedies (e.g., pumping lost circulation pills and squeezing) have given way to popular wellbore strengthening solutions. Our approach to strengthening, based on beneficial manipulation of fracture propagation pressure and continuous application of specialized wellbore strengthening additives has had tremendous success in reducing downhole mud losses by more than 80% in Gulf of Mexico deepwater operations and dropping the cost of these incidents out of the top 10 contributors to NPT. This paper focuses on the various theories and approaches to wellbore strengthening and what the available field and literature data actually support. Building upon this, the approach of gaining wellbore fortification through fracture propagation resistance (FPR) enhancement is introduced, for which experimental results, field data and case histories are shared. Central to our application of FPR to drill challenging deepwater production wells is the notion of providing continuous wellbore protection through a novel and unique solids recovery and reintroduction method that allows for drilling with high concentrations of wellbore strengthening materials (WSM) in the drilling fluid. Introduction Delivering Gulf of Mexico (GOM) deepwater wells is complicated by the presence of high geopressures and relatively low fracture gradients leading to very small drilling margins. Lost circulation into induced or natural fractures in particular has been a prevalent source of non-productive time (NPT) and associated trouble cost, associated with events where copious amounts of drilling fluid are lost, contingency casing strings need to be run, lost wellbores need to be re-drilled or sidetracked, etc. Moreover, the deepwater lost circulation challenge is growing as:prospects start to deplete from ongoing production, further reducing already small drilling margins; geomechanical changes associated with depletion and subsidence increase the risk of fault (re-)activation, leading in turn to the sudden appearance of lost circulation zones and problems never before encountered; wells much more challenging from an equivalent circulating density (ECD) perspective, such as extended reach wells approaching 10+ km in total depth, are drilled to more marginal pockets of hydrocarbons. It is little wonder that the industry has devoted considerable attention and resources to developing wellbore strengthening methods that extend drilling margins to prevent severe mud loss, extend and/or eliminate casing string and seats, and guarantee high(er) quality cement jobs. It is important at this point to clarify what the term "borehole strengthening", in many ways a misnomer, really means. When conducting a formation strength test, the pressure response observed is determined to a very large extent by in-situ formation stress (and the tangential stress or hoop stress riser generated at the wellbore wall during borehole drilling) and to a much smaller extent by formation tensile strength, which for most formations of interest is either small or negligible in magnitude. Borehole strengthening methods therefore rarely target an increase in formation strength (although chemical treatments are available to enhance rock matrix strength in permeable formations, and have been applied successfully on depleted formations) 1, and are mostly concerned with either:attempting to enhance the near-wellbore stress, thus raising the threshold for fracture (re-)opening and growth; this approach will be referred to in the following as Wellbore Stress Augmentation (WSA), or increasing the formation's resistance against fracture propagation, referred to in the following as the Fracture Propagation Resistance (FPR) approach. The overall effect of these approaches is that the effective fracture gradient, i.e., the pressure at which fractures grow to significant size and large volumes of drilling fluid are lost, is elevated.