Summary Simple alterations to the completion can be used to enhance the performance of long horizontal wells producing from high-permeability formations. Production performance and operational feasibility of the investigated completion methods are compared. The methods should be considered for horizontal wells where frictional pressure losses along the perforated section restrict production performance. Introduction Inflow from the reservoir to a horizontal well in high-permeability formations can be severely restricted by the frictional pressure loss along the horizontal well (Fig. 1). For long horizontal wells with high production rates, considerable pressure loss is experienced along the horizontal part of the well. The liner pressure increases exponentially from the heel end toward the toe end of the well, and the drawdown and influx to the liner decrease accordingly. The effect of a declining drawdown along the well becomes important in high-permeability reservoirs where the pressure loss through the reservoir may be of the same magnitude as the pressure loss along the horizontal wellbore. The upstream part close to the toe of the well contributes less to the production than the downstream part close to the heel, and a severe reduction in well productivity is experienced. In thin oil zones, the drawdown will often be restricted because of gas and water coning, and maximum production rates may be limited as a result of coning problems rather than lack of downstream transport capacity. By reducing the effect from pressure loss along the wellbore, higher production rates can be maintained without causing gas or water coning problems to become more severe. In this study, optimization of completion design is based on three basic principles:reduction of the frictional pressure loss along the perforated part of the well,redistribution of the frictional pressure loss along the perforated part of the well by changing the flow direction in parts of the liner, andcreation of an optimal sandface pressure profile by introducing inflow control along the wellbore.
Proppant fractures along the horizontal laterals in the Valhall Field have become a standard completion method for the last eight years with over 150 proppant fractures completed to date. The development of the flank regions of the Valhall Field began, with the first of 14 wells completions, in March 2003. Lateral lengths of up 2,000 meters will be drilled from two new platforms placed on the North and South edges of the field. The chalk formation in the flank regions is expected to be more competent then the crestal part of the field, so the question was raised as to whether fracturing should be done with acid or proppant. From a proppant fracturing perspective, each flank well will require between 10 to 14 prop fractures along its lateral requiring 2.5–3.7 Million pounds of proppant per well. Three different methods have been used to determine whether the wells should be acid or proppant fractured. These consist of reviewing the historical well performance, analytical and numerical modeling. All three methods clearly showed proppant fracturing was the preferred stimulation for the Valhall Field regardless of it's location. Acid fracturing becomes the stimulation of choice only if the well does not come in contact with enough OOIP (e.g. 5 MMSTB) to justify the proppant fractures. Proppant fracturing is expensive, so in conjunction with identifying the best stimulation method for the flank region, optimization with respect to fracture spacing along the horizontal lateral, fracture length and width have been numerically modeled for both the crestal and flank wells. This is an evolving process that should be considered an industry "Best Practice" as it enables real time optimization of ‘prop’ fracturing along a horizontal lateral during the drilling and completion phase. Since the start of this "Best Practice" in 2002, the wells stimulated in the crestal part of the Valhall Field have had the highest productivity in the field's history. Introduction The Valhall Field is an Upper Cretaceous, asymmetric chalk anticline that forms an overpressured, under-saturated, oil reservoir located in the Norwegian sector of the North Sea (Figure-1). It is characterized by high porosity (25–48%) and high oil saturation (92–97%). In common with other chalk reservoirs in the region, the drive mechanism is a combination of fluid expansion and formation compaction. The production is mainly from the high porosity (35–48%) Tor formation, which exhibits typical thickness of 15–40 m and a permeability of 1–10 mD. The source rock is the organically rich Kimmeridigian Clay underlying the chalk and has resulted in a reservoir, which is over pressured for depth with an undepleted gradient of 0.78 psi/ft TD at 2,500 mTVD1. The field will recover over 1 billion STB with current production of 80,000 BOPD from 42 wells on the main Drilling Platform and the Wellhead Platform (WP), which are centrally located in the crestal part of the field. The field was originally sanctioned and placed on production back in 1982 with reserve estimates of only 250 MMSTB. Reserves have increased by 400% since then throughbetter reservoir description,improving the completions and drilling strategy from vertical indirect proppant fractures to long horizontals with multiple proppant fractures, andthe current development of the flank areas of the field and the initiation of a waterflood in the crestal section.
Summary The Eldfisk oil field is a high-porosity, low-permeability reservoir of soft chalk in the Norwegian North Sea. Commercial oil production from the Eldfisk field is dependent on well stimulations. To date, pseudolimited-entry acid stimulation (PLEAS) has been the standard completion technique. This technique initiates relatively high (5,000 BOPD) individual-well oil-production rates. Over time, however, many of the Eldfisk wells have experienced rapidly declining oil production characterized by wellbore skin increase and fracture closure. Solids production and casing collapse have also been problematic. In late 1997, an alternative completion technique involving four hydraulic propped-fracture stages was successfully executed in an Eldfisk horizontal well. This paper presents a simple methodology to evaluate sustained productivity enhancement of propped fractures vs. acid stimulations in soft chalk formations based on the use of analytical modeling in combination with empirical production-data analysis.
The development in drilling and completion technology for horizontal wells has created new demands for enhanced comprehensive simulation methods. Wellbores with complex flow geometrics are not easily implemented in commercially available simulation tools. A modular, comprehensive modelling of well and reservoir is proposed in this paper. The model consists of a detailed horizontal well flow simulator coupled to a reservoir simulator. The wellbore simulator is based on a network mode] which is capable of solving a broad range of possible flow configurations in the horizontal part of the well. The modular approach is facilitated by a coupling technique that reduces the requirement for iteration between the modules. The simulator is applied to high flowrate horizontal wells in thin oil zones with high permeability. Due to the flexibility in wellbore configuration, the simulator may be used to optimize well location, well path and completion approach. The coupling provides a detached wellbore simulation module which is reservoir simulator independent. The new simulation approach should be considered for horizontal wells where frictional pressure loss or geological inhomogeneities along the well are of importance to a well's production performance. The simulator will be used to evaluate completions with a complex flow configuration, potential cross-flow and for optimization of production and injection performance of wells in heterogeneous reservoirs. Introduction Optimizing the inflow to long horizontal wells has been recognized as a critical research area with a high potential for increased production rates. New completion designs for horizontal wells have recently been proposed for improved well productivity and reduced production problems. A typical inflow control liner design for use in high permeability, thin oil zones is shown in Figure 1. Efficient use of these completion designs requires that the flow inside the completion can be calculated in a more detailed way than what is possible with available reservoir simulation packages. Thus, a detailed flow simulator for horizontal well completions was developed for modular integration with reservoir simulators. The modular simulator approach is illustrated in Figure 2. The implementation of a detailed near wellbore simulator as indicated in the figure is recognized to be of great importance for prediction of local geology effects on the inflow, but was not within the scope of this study. A modular, comprehensive simulation of the reservoir and the well has shown to be feasible through a coupling project involving a detailed horizontal wellbore simulator (HOSIM) and a 3D, two phase reservoir simulator (FRONTSIM). Based on the experience from this coupling project, a modular. iterative coupling approach was developed between HOSIM and a general black oil reservoir-simulator, which we refer to as RESIM. Enhanced Wellbore Simulation The horizontal wellbore simulator (HOSIM) is based on a general network solver for calculation of steady state flow through wellbore completions. The network solver which was originally developed for use with gas pipeline systems has been modified to perform steady state simulation of horizontal wells. As the network solver also is capable of determining the direction of flow, the simulator can be used for injection wells as well as for indicating cross flow between formations. P. 109^
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