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.

The Erha field is a deepwater subsea oil development located in OML 133 off the coast of Nigeria. Erha North is a satellite of the Erha Field and is characterized by multiple unconsolidated sand intervals separated by shale sections. Due to the potential for reservoir compaction and early water breakthrough in these multi-layered Erha North reservoirs, high rate water injection is an important element of primary production through pressure support and is considered critical to project economics and reserves capture. This paper presents a case history of a successful field application of an innovative water injector completion technique addressing the issue of long-term injection conformance. Standalone screens with flow-control devices (i.e., downhole chokes) and openhole packers were utilized on the two most challenging water injectors in the Erha field. The completion objectives were:(a) target multiple intervals to reduce well count and cost,(b) sustain target injection rates and allocations, and(c) install sand control to prevent wellbore fill. Traditional water injector completion techniques, such as frac packs or openhole standalone screens, were judged to be incapable of meeting all the completion objectives. Unfractured completions, such as openhole standalone screens, have been reported to lose injectivity over time due to plugging and require fracturing to sustain injection rates (Sharma 2000). Fracturing may result in poor injection conformance and has the potential for broaching cap shale. Application of stacked completions or intelligent well systems would have added significant cost and complexity. Detailed completion simulations and fracture modeling were conducted to design the completions to their unique geologic settings. It is expected that this completion technique will maintain the desired injection allocations to the multiple target intervals over the well life in the matrix and fracture injection regimes. Upfront planning, communication, and alignment between reservoir, subsurface, and drilling functions enabled a successful real-time completion design and resulted in an operational success with less than 5% completion non-productive time (NPT). Performance of the injectors is being monitored by downhole pressure and temperature gauges. Introduction Water injection has been a successful secondary recovery technique in the oil industry for many years. In the past 10 to 15 years, however, projects have been developed where high-rate water injection is a primary recovery method because completion reliability and economic constraints require early voidage replacement and pressure support. As water injection becomes integral to the economic justification for capital intensive (i.e., offshore, subsea) projects, considerable attention to the design and performance of the water injectors is required. Regardless of rock cementation, there are very few documented cases of long-term, high-rate water injection without some form of continual or periodic stimulation. In well cemented rock formations, successful high-rate water injection programs rely on continual formation fracturing. Highly compressible, uncemented sands such as those found in many deepwater reservoirs, including those in the Erha North Field, do not easily fracture. High-rate water injection into such sands has been very difficult for some operators even when these sands have multi-Darcy permeability. In Yemen, one operator has experienced a "check valve phenomena" when attempting to inject water into an uncemented formation. Formation water was produced at a productivity index of 400 bwpd/psi, but later attempts to reinject that same water resulted in an injectivity index of less than 10 bwpd/psi (Wilkie 1996).

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.

Long-term completion performance is important for the economic development of any field. As fields are now developed in environments that are capital intensive and increasingly technically challenging, new technologies are required for optimization of the completion design. Stand-alone reservoir simulators lack the required detail on the completion side, while stand-alone wellbore simulators do not have the long-term reservoir performance information available. Even the new class of coupled wellbore/reservoir simulators often lack comprehensive completion design capabilities. We have developed a fully-coupled black-oil wellbore/reservoir model which accounts for the necessary details for an optimized completion design. Specifically, the model couples ExxonMobil's proprietary reservoir simulator and a detailed completion hydraulics simulator such that the reservoir flow, wellbore tubing and annulus flows, and pressure fields are simulated simultaneously. In this paper, we compare different synthetic cases involving open-holes, pre-drilled liners, packers, and inflow control devices that demonstrate unique completion opportunities captured by using our modeling capabilities. We show that our model provides not only detailed information regarding the tubing and annulus flow and the associated pressure drops along the completion, but also the impact of different completion types on short- and long-term reservoir recovery. Our results show the significance of this new coupled approach in its ability to relate the reservoir performance and the flow dynamics through various completion types.

In this paper, a new carbonate stimulation methodology and its impact to the planning of very long, open hole completions will be presented. While the key objective of stimulation is to connect the well to the reservoir, completion equipment design and related well performance have become more important factors. Traditional methods of stimulation modeling and fluid placement are no longer sufficient for these types of wells. This paper introduces how completion design becomes more complex for more aggressive stimulations. For example, completions with pre-drilled or slotted liners for stimulation with coil tubing acid wash are less sophisticated than ball drop liners for high-volume acidizing or fracturing. In long horizontal completions, computer modeling of stimulation needs to address the flow conditions caused by liners, swell packers and inflow control devices (ICDs). Recent well planning for a long horizontal pilot well (Pilot Well 5) has included the use of new carbonate matrix stimulation software to design a fit-for-purpose completion liner that will accommodate bullhead treatment of a long completion interval. Various completion designs were considered based on objectives from reservoir engineering and geology. Being part of a pilot well program, the strategy is to test fit-for-purpose liners that would balance completion cost with long term productivity and recovery. The well design required more than 100 runs of the new carbonate matrix acidization software to finalize a liner design that employs over 200 holes distributed along the length of the lateral. The final design was developed to accommodate uncertainties in the reservoir properties and allow for safe and reliable rig operations. The resulting design could serve as a lower-cost alternative to ball drop stimulation liners for long openhole completions.