The Groningen Gas Field in the Northern Netherlands is the largest gas field in Europe and has been producing since 1963. Small magnitude seismic events in this seismologically quiet region were first observed in the early 1990's and linked to gas production. The objective of the work described here is to advance the understanding of subsurface deformation induced by gas production by including hundreds of mapped faults and fault-offsets to (i) characterize subsurface behavior related to production-induced fault reactivation, (ii) evaluate alternate production strategies to help manage subsurface stresses to reduce fault slippage which can lead to seismicity, and (iii) integrate with a seismological model for prediction of seismic activity rate. The multi-scale modeling framework includes a global model to capture full-field phenomena and three sub-models for regions with observed seismic activity which honor conditions of the global model, but also include explicit modeling of multiple faults. This approach considers the following features: i) Irregular stratigraphy and fault surfaces, ii) Non-uniform reservoir rock properties based on porosity, iii) Non-uniform pressure depletion mapped from reservoir simulations, iv) Relaxed deviatoric salt stresses at start of production, v) Salt creep effects during production, vi) Biot coefficient effects for reservoir rocks, and vii) Coulomb friction behavior to capture slippage along faults. The geomechanical models are used to better understand subsurface behavior related to production induced compaction and fault reactivation. Several production scenarios are analyzed and compared on a relative basis based on the predicted dissipated energy. The slip and contact force data for all finite element (FE) nodes on the fault surfaces are used as input to the seismological models for prediction of seismic activity rate. Results show the fault offset is a key factor for production induced fault slip. A fault with offset can develop slip due to differential compaction on two sides even if the dip and azimuth are not favorable for fault slip. This leads to more slip on significantly more faults compared to that in previous models without offsets. Initial seismological model results based on slip data predicted by present models show good correlation with observed seismic activity rate. Models rely on input parameters such as fault friction coefficient, rock properties and initial stress conditions that have some degree of uncertainty. To address the impact of these uncertainties, sensitivity analyses with a range of input parameters were undertaken which yield a range of outcomes. The use of quasi-static geomechanical models for predicting seismicity attributes is an evolving field and additional improvements or alternative correlations may be identified in the future. However, current model results are used to compare various production scenarios on a relative basis or for correlations in seismological modeling, and the parameters are expected to be consistent between scenarios.

The Groningen Gas Field in Northern Netherlands is the largest gas field in Europe with production starting in 1963. Seismic events were first observed in 1986, but these were generally small with minimal damage. A government study concluded in early 1990’s that tremors were linked to gas production. The objective of the work described here is to utilize advanced geomechanical modeling to (i) characterize subsurface behavior related to production-induced fault reactivation, and (ii) evaluate alternate production strategies to help manage subsurface stresses to reduce fault slippage which can lead to seismicity. Multi-scale 3D geomechanical models were developed using a non-linear quasi-static finite element method. This modeling framework includes a global model to capture full-field phenomena and two sub-models for regions with observed seismic activity which honor conditions of the global model, but also include explicit modeling of multiple faults. This approach considers the following features: i) Irregular stratigraphy and fault surfaces, ii) Variable reservoir rock properties according to porosity changes, iii) Non-uniform pressure depletion derived from field data and reservoir simulations, iv) Relaxed deviatoric salt stresses at start of production, v) Salt creep effects during production, vi) Biot coefficient effects for reservoir rocks, and vii) Coulomb friction behavior to capture slippage along faults. Models are verified by comparing predictions for the production history period (1964 – 2012) with corresponding field data. The model predictions for production forecast period (2012 onwards) are used for relative comparison of various production scenarios. Subsidence and reservoir strains calculated from the full-field global model during production history match well with corresponding field data without the need for calibration of material properties. Model results show that the fault frictional dissipated energy correlates well with the radiated energy from observed seismic events, and that the energy scaling factor associated with this correlation is constant and the same for both sub-model 1 and 2. The dissipated energy during frictional sliding is a scalar quantity that provides a representative measure of fault activity for a given area of interest. Furthermore, because the dissipated energy correlates well with observed radiated energy, the models can be used for relative comparison of production scenarios to identify strategies that reduce fault loading. Several production forecast scenarios are analyzed and evaluated based on predicted frictional dissipated energy to assess fault slippage. These results indicate that curtailment of production alone is not an effective alternative for mitigation of energy dissipation and related seismic activity. This study shows that advanced geomechanical models are a powerful tool that can provide valuable insight into the overall trend of cumulative radiated energy, are useful in understanding seismic activity, and can be used to identify production scenarios that mitigate seismic activity.

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Thw paper was prepared for presentatmn al tfw Western Regional Meeting held m Anchorage, Alaska, 22-24 May 199S This paper was selec!ed lor presentahon by the SPE Prcgram Comm!tlee folfowmg revmw' of Informalton cnntamed In an abstracf submmed by the author(s) Contenls of the paper as presented, nave nO[ been rewewed by the Soctety of Petroleum Engnwers and are subjecf to correcton by the authcr(s) The maternal, as presented, does not necassanly reflecf any POSIIIO"of the Society of Petroleum Engtneers or idsm-mbersPapers presented a[ SPE meetlcgs are subject 10 publlcatum rewew by Edional Comm!ttee of the SomBly of Petroleum Engineers Permwsmn to COPY!s restricted to an abstract of not more than 3C0 works Illustrations may not be coped The abstract should contain conspicuous acknowledQmam of where and by whom the IXILI.X was presemed WWo L\brarvan, SPE, P O 833836 Rlchardso", TX 75083-3836 USA, fax 01 -214-952:!+435 ABSTRACT Production of fluids from the shallow, thick, and low-strength Diatomite reservoir in the South Belridge field has resulted in reservoir compaction, surface subsidence, and numerous well failures. The most severe subsidence problems occurred while the field was under primary recovery, prior to implementation of waterfloods for pressure support, Consequently, a significant number of wells in the field have incurred casing damage, which proportionate y limits the utility of these wellbores for cent inued production and routine wellwork operations. The nature of casing damage varies significantly depending on the location in the field, however casing shear ("kinks") generally produces the most severe problems in retaining full wellbore utility since it Iim its tool passage (e.g., packers, scrapers, etc.) and is not economically repairable using conventional milling tools. Since the mid 1980s, surveillance activities have been in place to monitor and assess the magnitude and progression of surface subsidence, reservoir compaction, and wellbore damage in Section 19 of the South Beh-idge field. Surveillance activities include the use of ground elevation markers and a variety of production logs --several of which involve novel application and log interpretation. These data subsequently were used to develop and verify hybrid geomechanics and wellbore geometric models for assessing casing damage, identifying well operability and wellbore utility limits, and forecasting remaining wellbore life from which a reservoir management plan and wellbore management operational strategies were established. A key ingredient in the implementation of this plan and operational strategies involved a cooperative tool development with a major oil tool service company to repair casing "kinked" wellbores, as an alternative to re-drilling wells. This paper provides a case history describing the various synergistic reservoir and wellbore management activities designed to effectively mitigate subsidence-induced operational problems and the accompanying field benefits resulting from their implementation. INTRODUCTION The Sou...

Ensuring long-term optimum completion performance is important for the economic development of any field. As fields are now developed with fewer wells and in more technically challenging environment, new technologies are required to provide guidance and quantify the impact of completion design. This paper presents a new methodology in coupling ExxonMobil's reservoir simulator and a detailed well hydraulics simulator that simulates reservoir, wellbore tubing and wellbore annulus flow simultaneously. Case studies indicate that unique completions opportunities in optimizing completions options, especially inflow control devices, are captured by using the modeling capabilities Completion strategies frequently include provisions tomaintain a uniform production profile along the wellbore,manage future risks (early water or gas breakthrough) and mitigate the potential for sand production, andimprove reservoir recovery. Completion options include open hole, cased hole, inflow regulation devices (inflow/flow control devices and inflow valves), sand screens, or pre-drilled liners. Different from nodal based wellbore simulation in a conventional reservoir simulator, the proposed coupled well and reservoir simulation provides not only detailed information on the tubing and annulus flow and associated pressure drops in and throughout all completion types, but also the impact of completions on short and long term reservoir flow and recovery. Studies have shown the importance in utilizing the coupled model in both history matching and model prediction when advanced completions are applied. The significance of this new coupled approach is its ability to capture both flow dynamics through various completion options and reservoir performance Introduction In the past, top performing fields produced thousands of barrels a day from each of dozen of wells with completions lengths spanning tens to hundreds of feet. Today, we are using far fewer wells, each producing tens-of-thousands of barrels a day, from much longer and more complex completions often spanning thousands of feet, and all of this in more technically challenging environments. Obtaining superior well performance requires both a better understanding of the physics that controls well production as well as new technologies that take advantage of physics-based knowledge. ExxonMobil develops unique, physics-based modeling capabilities that can be applied during well planning, design, and production to deliver optimized well performance over a well's life-cycle 1. Well completions are important means to optimize well performance throughout the entire well life, especially for challenging and remote environments. Commonly available completions options include open hole, cased hole perforated, slotted liner, inflow control devices (ICD), perforated liner, wire wrapped screen, gravel pack, frac pack, etc. For example, in ExxonMobil's Sakhalin-1 development, a combination of external isolation packers, inflow control devices, sand screens, and pre-drilled liners were used and the factors that were considered to configure the completions include rock strength, sand particle size, reservoir deliverability, reservoir description, etc.3 The challenging part from a completion design point of view is the understanding well inflow and outflow performance as a result of pressure drops due to multiphase flow in and throughout all completion types. More importantly, how the well inflow and outflow performance change over time. All these are the fundamentals for completion optimization - physics-based completion design, practices, and procedures for optimizing the selection, design, execution, and operations of wells in consideration of lifecycle risks and costs.

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Summary. Drillstring failures continue to plague the oil industry, often costing millions of dollars each year. This problem is frequently intensified with the drilling of deep, deviated wellbores or "hard rock" drilling conditions. The drilling industry attempts to guard against these costly failures by performing periodic nondestructive inspections to remove damaged tubulars from service. This paper describes the results of full-scale fatigue-crack-growth tests of drill collars under rotating and bending loads. In addition, corrosion fatigue-crack-growth data are also presented for API drillpipe steels in air and in three representative water-based drilling-fluid environments. Based on this experimental investigation. the test data support the practical application of fatigue-crack-growth mechanics principles for the development of nondestructive inspection intervals to reduce drillstring failures. Introduction Failures of drillstring tubulars are costly to the oil industry in the form of lost rig time, damaged tubular goods, and abandoned or side-tracked wells. Based on drilling records, costs associated with a downhole separation of the drillstring average about $106,000 per occurrence and have been estimated to occur on about 14% of all wells. The majority of these failures are recognized as being some form of metal fatigue. The fatigue mechanism is a progressive one. Under the action of fluctuating stress and corrosion, microscopic cracks form, become macroscopic in size, and then propagate through the wall thickness until failure. In addition, stress "raisers," such as machining scratches, slip marks, and formation cuts, have been known to accelerate fatigue-crack initiation. The oil industry currently guards against these costly failures through periodic nondestructive inspections to check for macroscopic cracks. Inspection intervals traditionally have been selected on the basis of experience in a given area or through the use of guidelines established by Hansford and Lubinski in the early 1960's. This "classical" approach is fundamentally sound for the prediction of fatigue life. This approach does not, however, provide information regarding crack growth from which nondestructive inspection intervals may be specified to avoid failure. Within the last 25 years, though, significant effort has been directed toward better understanding of fatigue-crack-growth behavior. A new philosophy known as "defect-tolerant" design--the principal concept that all structures or components possess defects, either from manufacture or from service--has evolved into engineering practice. Consequently, the fatigue life can be established based on fatigue-crack growth. Nondestructive inspection plays a very important role in defect-tolerant design in that critical flaws (i.e., defects) must be identified and either removed or repaired to avoid failure. The application of fatigue-crack-growth mechanics principles has been widely accepted and practiced by the aerospace/air-craft industries. power generation utilities, and defense contractors, in addition to the offshore structures and pipeline communities within the oil field. This paper describes the results of full-scale rotating/bending fatigue tests on drill collars and corrosion fatigue material tests of API drillpipe steels. The results of this paper support the practical application of fatigue-crack-growth mechanics principles for drill-string tubulars. Background Information A brief review of the terminology associated with the principles of fatigue-crack-growth mechanics is warranted. Fig. 1 illustrates the basic material relationship between fatigue-crack growth rate, d a/dN,* and Mode I stress-intensity fluctuation, delta KI. Stress-intensity fluctuation is a function of fluctuating (cyclic) stress and crack depth, but is also influenced by other variables such as geometry and crack shape. As can be seen, there are three distinct regions of fatigue-crack growth. Region I is referred to as the "threshold" regime, where fatigue-crack growth rate is very slow. Region II is referred to as the "Paris" regime (after the man who first observed this behavior), where fatigue-crack growth rate is found to obey a power-law relationship with stress-intensity fluctuation. Region III is referred to as the "unstable" regime, where fatigue-crack growth rate is very rapid and brittle fracture is imminent, For practical engineering applications, Region II is of greatest importance and is described by Eqs. 1 through 4. (1) (2) (3) and (4) Full-Scale Rotating/Bending Fatigue Tests Drillstring connections, especially those on drill collars, are particularly susceptible to fatigue failures. Therefore, they were the focal point of this investigation into the fatigue-crack-growth behavior in drillstring tubulars. Full-scale rotating/bending fatigue tests were conducted on 6 1/4 -in. [15.9-cm]-OD × 2 1/4 -in. [5.7-cm] -ID drill collars to determine the rate of crack growth at various locations within the connection. Both API NC-46 and 4 1/2-in. [11.4-cm] H-90 connections were tested. Test Apparatus. All fatigue-crack-growth testing was conducted with a fully instrumented, servo-controlled, hydraulically actuated, closed-loop, four-point rotating/bending test frame. Fig. 2 shows an overall view of the test frame and control/data acquisition instrumentation. SPEDE P. 356^

MazeFlo™ technology enables a sand control screen to self-mitigate mechanical damage and improve reliability in sand-prone well production. A self-mitigating screen uses redundant sand control screens and compartment baffles to restrict the effects of any mechanical screen failure to a local compartment. The hydrocarbon flow continues intact through the remaining undamaged screen compartments. This innovative, patented technology is being commercialized in collaboration with a selected service company. This paper reviews the initial design and development of the self-mitigating screen prototype. The screen design balances flow hydraulics, well performance, mechanical integrity, and manufacturing complexity all while maintaining practical screen dimensions. Successful self-mitigation, after failure of an outer screen, requires that the incoming sand packs a compartment to shut off the flow path before any significant erosion occurs along the flow path to the redundant inner screen. The baffles are configured to both redirect fluid momentum from any "hot spot" inflow at the outer screen and impose a minimal friction loss during production through undamaged compartments. Each component in a compartment is designed to sustain erosion from the incoming sand of a failed outer screen. The offset outer and redundant inner screens are sized to minimize the impact on productivity when compared to conventional screens. The mechanical strength of the self-mitigating sand screen is also targeted to be equivalent to conventional screens. Development of the self-mitigating screen prototype is proceeding and includes extensive qualification by multiple modeling techniques and physical testing. The innovative, self-mitigating capability expands the current operating limits of screens in sand control completions. In a broader view, the self-mitigating screen enhances overall reliability and longevity and can be integrated with other emerging technologies such as openhole zonal isolation, inflow control, and intelligent wells for enhanced production flexibility. MazeFlo sand screens will expand ExxonMobil's suite of innovative sand control solutions that include Alternate Path® technology, NAFPacSM process, openhole gravel packing with zonal isolation, and customizable sand control for extreme length completions and injection conformance.