This paper outlines a general concept and develops a practical well surveillance method to monitor and operate sand control completions that optimizes production without introducing extra risk of completion impairment and failure. The general concept requires:determining the sand control failure criteria that the surveillance method should be based on,establishing a direct link between the identified failure criteria and pressure transient analysis information, andvalidating the surveillance method. The proposed surveillance method utilizes readily accessible well information without requiring production log measurements of down-hole velocities within the completion interval. The proposed method is fully developed for cased hole, gravel pack completions assuming the gravel-filled perforations dominate flow within the completion. The equations are given and velocity criteria are established. In this case the two dominant completion failures are screen erosion and destabilization of annular pack. The maximum flowing velocities for these failure mechanisms can be established using field production logs, laboratory screen erosion data, and mathematical calculations of fluid flow in the annulus pack. The pressure drop across the gravel packed perforation tunnel is the dominant completion pressure drop for the cased-hole gravel pack system. This pressure drop equation is non-linear or proportional to square of perforation flowing velocity. The well surveillance method monitors down-hole flowing velocity and completion pressure drop to operate the well without introducing unnecessary completion impairment and sand control failure risks. The process of ramping up the well and determining a safe maximum rate goes beyond the strict adherence to absolute values of acceptable completion pressure drop and down-hole velocities and is integrated with prudent surveillance. The method recommends several pressure transient analyses be taken, at increasing flow rate, during the process of ramping up toward the peak rate, to help assess and diagnose the performance of the completion. This integrated assessment by direct measurement of completion pressure drop and corresponding calculation of flowing velocity provides real time feedback of information on the performance of the completion during the ramp up process. Using this direct and simple process, engineers can customize the operating guidelines for each well so that less impaired wells can be produced at higher rates and the more impaired or higher risk wells are identified for remedial operations and produced less aggressively. This paper demonstrates the application of the proposed concept and surveillance procedure, in reaching the peak rate, for the cased-hole gravel pack completion. Three field examples are provided to illustrate how engineers are able to use standard pressure transient analyses and the proposed simple method to assess the completion response to each additional choke increase and to optimize well productivity during the ramp up process. This paper summarizes key findings on the implementation of this new integrated surveillance tool. Introduction The economics of developing unconsolidated sand and geo-pressured reservoirs in deepwater in the Gulf of Mexico (GOM) increasingly demands fewer wells per project. These wells need sand control completions and require higher production rate and higher ultimate recovery per well. Production from each well is more critical which highlights the importance of maintaining well productivity and minimizing completion failure risk. Proper selection, effective design, rigorous quality assurance and control of equipment and field execution procedures of sand control completion have been recognized to be essential for meeting productivity and reliability requirements.1,2 However, for geo-pressured reservoirs the higher reservoir pressure also provides the potential of delivering greater rate with higher production drawdown and larger tubing. This approach elevates the need for developing well surveillance guidelines to operate these wells without impairing and failing the sand control completion.

Often, pressure-gauge systems for surface read-out (SRO) wireline work or for permanent installations do not perform according to their specifications; i.e., the pressure resolution obtained is lower than the gauge-design values. This seems natural because the borehole environment is nastier than the quiescence of laboratory calibration set up. Nevertheless, it is difficult to attribute the loss of resolution to a single problem.This paper introduces the functional components of the pressuregauge system where loss of resolution may occur. Specifically, it addresses cable-related problems, crossover, signal transmission, signal processing, time stamping, and temperature compensation. We show determination of pressure resolution from a processed signal by means of example calculations. The role of transducer specifications on overall data quality is addressed; i.e., what causes a 0.01-psi-rated transducer to yield a signal of only 0.75 psi quality? Field data from Tahoe and Bullwinkle prospects are used to illustrate some of the gauge-related problems and the solutions being proposed by the industry to overcome some of them.

The need to better estimate the performance of hydraulically fractured wells in shale-gas formations has focused attention on the description of the non-Darcy flow in the region of the hydraulic fracture near the borehole where the converging flow may be increasingly dominated by the inertia effect. The analogy between high-rate flow in proppant-filled hydraulic fractures-best described by the Forchheimer equation-and the flow of reactants in fixed beds or granular beds in catalysis-widely described by the Ergun equation-may offer insights on how to estimate the value of the coefficient b across the complete range of velocities (or, equivalently, Reynolds numbers). In this paper, we show that, although the value of b varies over a wide range depending on the porosity (/) and permeability (K) of the porous medium, the value of the product bK is confined in the range of 10 À5 to 10 À4 m, and a correlation is obtained with narrower uncertainty compared with published ones.

Summary The classic plots of dimensionless fracture conductivity (CfD) vs. equivalent wellbore radius or equivalent negative skin are useful for evaluating the performance of hydraulic fractures (HFs) in vertical wells targeting conventional reservoirs (Prats 1961; Cinco-Ley and Samaniego-V. 1981). The increase in well productivity after hydraulic stimulation can be estimated from the “after fracturing” effective wellbore radius or from the “after fracturing” equivalent negative skin. However, this earlier work does not apply to the case of horizontal wells with multiple fractures. A revision of the diagnostic plots is needed to account for the combination of the resulting radial-flow regime and the transient effect in unconventional reservoirs with ultralow permeability. This paper reviews and extends this earlier work with the objective of making it applicable in the case of horizontal wells with multiple fractures. It also demonstrates practical application of this new technique for fracture-design optimization for horizontal wells. The influence of finite fracture conductivity (FC) on the HF flow efficiency is evaluated through analytical models, and it is confirmed by a 3D transient numerical-reservoir simulation. This work demonstrates that a redefined dimensionless fracture conductivity for horizontal wells CfD,h = 4 is found to be optimal by use of the maximum of log-normal derivative (subject to economics) for HFs in horizontal wells, and this value of CfD,h can provide 50% of the fracture-flow efficiency and 90% of the estimated ultimate recovery (EUR) that would have been obtained from an infinitely conductive fracture for the same production period. This new master plot can provide guidance for hydraulic-fracturing design and its optimization for hydrocarbon recovery in unconventional reservoirs through hydraulic fracturing in horizontal wells.

Summary One of the major challenges in efficiently developing ultratight or shale reservoirs is to obtain reliable permeability distribution. Ultralow permeability and very strong stratification or heterogeneity in the formations require conducting long-duration tests at multiple locations in a well to attain a complete reservoir characterization. Because of these characteristics, existing tools or methods that work well for conventional reservoirs are usually not applicable for ultralow-permeability formations. An innovative reservoir-monitoring/testing tool system was developed and successfully applied to fields in both the United States and Canada (Zhan et al. 2016). The tool created multiple pressure pulses at targeted locations simultaneously along monitoring wells for zonal in-situ permeability estimations as well as long-term formation-pressure monitoring. Existing pressure-transient solutions are incapable of handling the measured data when potential zonal-pressure interferences appear. A fit-for-purpose pressure solution, the associated optimization algorithm, and a suitable data-interpretation work flow were developed to analyze the data whenever commercial software tools are inadequate. The new solution fully considers all impulses as well as potential interferences among them through suitable superposition. In-situ permeability values at all involved zones can be obtained through a combination of individual-impulse analyses and systematic multiple-impulse inversions. The new pressure-transient solution was verified through comprehensive synthetic cases using numerical simulations. The results show that the solution can handle either fully or partially open wellbores in each zone and properly considers crossflow between formation layers. In addition, it allows any number of perforated intervals and formation layers where the number of perforated intervals is fewer than that of the formation layers. Field examples demonstrate the applicability of the new solution and the data-interpretation work flow to formation permeability down to tens of nanodarcies. The detailed zonal-permeability distribution in the formation enables a more-representative reservoir model for better hydraulic-fracturing design and field-development optimization.