Integrated Sand and Erosion Alarming on Na Kika, Deepwater Gulf of Mexico

Abstract

A pilot test of an integrated sand and erosion alarming process has been implemented in the NaKika field, in the Gulf of Mexico. All wells have sand control completions. Except for one well with a gravel pack completion problem, all the other wells are controlled by a flux limit (SPE Paper 84495). A Microsoft Excel based program was developed to automatically receive daily morning report data, and perform nodal analysis calculations on all of the wells, in order to estimate: mechanical skin corrected for relative permeability changes, pressure drawdown, gravel pack flux, and wellhead velocities. The wellhead velocities were utilized to calculate erosion rate to estimate metal loss. Corrosion rate at the wellhead was also estimated. All calculated results are sent to OSI PI as data tags and viewable through a commercial real time trend-analysis program. The Excel program results are also automatically emailed to the engineers. The gravel pack flux limits are used to make sure we do not produce the wells at rates which increase the probability of sand control failure. Monitoring of the flux results were subsequently used to increase the gas rate of one well by 15 MMSCF/D, and an oil well by 4.8 MBOE/D. Wells were ramped up in a controlled manner via programmable logic controllers. Acoustic sand detectors showed very little sand production, primarily during ramp up. The controlled ramp up is believed to be the most important reason that we have not observed any sustained sand production. After a year of operation, we have had only one minor separator cleanup for sand, most of which has been proppant from double and triple frac packs. Introduction BP produces from the NaKika host a collection of oil and gas fields in 6300 ft of water in the Gulf of Mexico. All wells were developed with sub sea completions. The various oil and gas wells produce from the Miocene age sands. There are ten wells, seven that produce from oil bearing sands, and three that produce from gas sands. Individual oil wells produce as much as 35,000 STB/D, and one gas well has produced as much as 168 MMSCF/D. The formations are prone to produce sand. Eight of the wells are completed with frac pack completions. In some cases, there are double frac packs with sliding sleeve completions, and in three wells, there are three commingled frac packs. Two wells are horizontal with open-hole gravel packs. One of those wells failed to have all of the sand placed behind the screen. The nine wells with good frac pack and gravel pack completions were limited by the flux through the gravel pack. Tiffin et el1 discussed how oil and gas wells with sand control can be controlled by monitoring flow through gravel pack screen to minimize the risk of screen erosion. Tiffin et el1 reported that a high frequency of screen erosion failures occurred when the flux exceeded 60, and no failures occurred below 60. The well with a poorly executed gravel pack completion was draw-down limited. Oil and gas fields that produce sand can have erosion at the wellheads, wellhead chokes, wellbore restrictions, and topsides. A common practice is to perform erosion calculations for the maximum expected velocities through various piping. Corrosion can be made worse in sand prone environments because erosion and corrosion can work together to yield greater metal loss. While the tubing and wellhead metallurgy is 13 chrome steel, carbon steel is used immediately after the wellheads.

Dynamic Modeling of Channel Formation During Fluid Injection Into Unconsolidated Formations

“…They tried to show that injection-pressure response depends not only on the instantaneous measurements but also on the whole history of injection. Parallel to works modeled after fracture propagation in water injectors, water hammer caused by fast shut-in of pumping systems was also identified as one of the main causes of sand production and loss of injectivity in weak formations (Tang and Ouyang 2010;Choi and Huang 2011). Despite the immaculate documentation of water-hammer effects in the field (Wang et al 2008) and elegant mathematical models (Han et al 2002) for this phenomenon, the source of attenuation is not well-understood in these models.…”

“…A successful water-injection system is essential for optimum field development by increasing oil recovery, maintaining high reservoir pressure, and minimizing the cost of handling the produced water. A number of publications in the last 2 decades have indicated issues including rapid injectivity decline, out-of-zone injection, and limited longevity of injection wells in the deepwater GOM that have plagued many of these developments (Sharma et al 2000;Stein et al 2005). Al-Kindi et al (2008) reported difficulties with water injectors in the Ursa and Princess fields in the GOM.…”

A New Methodology To Safely Produce Sand-Controlled Wells With Increasing Skin

“…Apart from the regular surveillance such as pressure-transient analysis, nodal analysis, and production testing, the asset is also using BP's flux-based approach (Tiffin et al 2003;Keck et al 2005) along with integrated sand and erosion alarming (Stein et al 2005). The integrated sand and erosion alarming allows the asset engineers to monitor in real time the completion integrity.…”

“…Our new methodology helps to quantify the risk and convert it into a safe target rate. This paper will also present case studies of oil and gas wells in the Na Kika asset in DW GOM where this methodology was applied successfully.The well completions are monitored with BP's flux-based approach (Tiffin et al 2003;Stein et al 2005;Keck et al 2005). In all cases, the wells experienced increased skin, causing the engineers to choke back the wells.…”

“…The well completions are monitored with BP's flux-based approach (Tiffin et al 2003;Stein et al 2005;Keck et al 2005). In all cases, the wells experienced increased skin, causing the engineers to choke back the wells.…”