Summary During frac-pack treatments, completion hardware is often subject to extreme differential pressures. This is especially true during early screenouts where the large hydrostatic differentials can suddenly be placed on the completion components, resulting in a high risk of collapse. Deep wells and completion-tool configuration can limit supporting pressures for these tools. To prevent damage to completion hardware such as crossover tools, fluid-loss devices, and blank pipe, the maximum surface treating pressure has been limited to a calculated Pmax (Jannise and Edwards 2007). Conventionally, the reservoir pressure was used as the internal supporting pressure in these calculations. Using the reservoir pressure to calculate the Pmax results in a worst-case pressure limit that prevents collapse in virtually any job. However, today many frac-pack treatments are being performed in low-pressure, subhydrostatic reservoirs. Many of these jobs could not be placed using just reservoir pressure for support, even when using high-strength, completion hardware materials. By analyzing a significant number of actual jobs, it was determined that the current standard equations are too conservative when compared to actual treating results. By using less conservative, modified equations, numerous additional wells have been completed with frac-pack technology. This paper studies a number of these successful frac-pack jobs that could not have been performed using the standard Pmax equation and safety factors. Postjob bottomhole-gauge data are examined to determine the true differential pressures and verify the accuracy of the assumptions that are used in the modified Pmax calculation, which provides valuable insight and recommendations for tool design, fluid properties, and maximum-pressure limitations for frac-pack completions.

Summary The Ursa-Princess Waterflood (UPWF) targets the Lower Yellow sand, the main reservoir in the Mars-Ursa basin in Mississippi Canyon, approximately 60 miles south of the mouth of the Mississippi River in the Gulf of Mexico (GOM). The Lower Yellow sand, a world-class Upper Miocene turbidite reservoir, has been on production in the Ursa and Princess fields since 1999, and has been drawn down nearly to the bubblepoint. The waterflood is intended to increase and stabilize reservoir pressure, and to improve sweep efficiency. To accomplish this, four subsea injectors were designed and constructed to inject treated seawater at 40,000 B/D each for a target life of 30 years. Because the Lower Yellow reservoir was already highly depleted, unique risks were identified in the planned subsea completion operations, to be conducted from a mobile offshore drilling unit (MODU). Seawater, used as a completion fluid, was expected to be up to 4,000 psi overbalanced to the reservoir, depending on the well location. This created the risk of either an uncontrollable fluid-level drop in the marine riser or an extreme impairment to the sandface completion. In order to maintain well control with a fluid level at the surface and still deliver low-skin completions, multiple design and procedural issues needed to be addressed, including the following: Control systems on the rig and riser system to prevent uncontrollable fluid-level drop. Perforating systems to minimize impairment in a highly overbalanced environment without adding undue risk to well control. Pill designs that could both control fluid loss at the sandface and clean up effectively. Downhole completion systems capable of functioning either under very high pressure differentials or against very high loss rates. Development of high-burst screens suited to the use of fluid-loss-control pills as a contingency provision in the event that mechanical fluid-loss devices failed. As more deepwater reservoirs approach depletion, specialized tools and procedures will be required to continue to deliver safe and effective sandface completions from floating rigs. This paper details many of these considerations and summarizes the execution experience and results for one such reservoir.

During frac-pack treatments, completion hardware is often subject to extreme differential pressures. This is especially true during early screenouts where the large hydrostatic differentials can suddenly be placed on the completion components, resulting in a high risk of collapse. Deep wells and completion tool configuration can limit supporting pressures for these tools. To prevent damage to completion hardware such as crossover tools, fluid loss devices, and blank pipe, the maximum surface treating pressure has been limited to a calculated Pmax.1 Conventionally; the reservoir pressure was used as the internal supporting pressure in these calculations. Using the reservoir pressure to calculate the Pmax results in a " worst case?? pressure limit that prevents collapse in virtually any job. However, today many frac-pack treatments are being performed in low-pressure, sub-hydrostatic reservoirs. Many of these jobs could not be placed using just reservoir pressure for support, even when utilizing high-strength, completion hardware materials. By analyzing a significant number of actual jobs, it was determined that the current standard equations are overly conservative when compared to actual treating results. By using less conservative, modified equations, numerous additional wells have been completed with frac-pack technology. This paper studies a number of these successful frac-pack jobs that could not have been performed using the standard Pmax equation and safety factors. Post-job bottom-hole gauge data is examined to determine the true differential pressures and verify the accuracy of the assumptions that are used in the modified Pmax calculation, which provides valuable insight and recommendations for tool design, fluid properties and maximum pressure limitations for frac-pack completions. Introduction As many fields are depleting and reservoir pressures falling, there has been an increase in interest in extending field life by the introduction of injection wells. This is especially true in deepwater fields where the cost of infrastructure is high. Although drilling and completing these depleted formations poses many risks, this paper will focus on surface pressure limits when placing frac-pack completions into these depleted formations. In the unconsolidated GOM sand completions studied, a tool string with a crossover service tool is used to place frac-pack completions. Typically, the maximum surface pressure is limited not by the surface iron or workstring burst ratings, but by the lowest collapse pressure rating in the gravel pack assembly below the crossover and above the top of the screen. This area may consist of crossovers, pups, fluid-loss devices, shear subs, blank pipes and similar types of hardware. In the event of a screenout, the gravel in the annulus above the screen forms a semi-impermeable plug, and pressure applied to the tubing string is directly transmitted to this annular area. This pressures attempts to collapse these gravel pack assembly components. When a " hard?? screenout occurs, the flow rate stops while the injection pressure spikes. Friction pressure is suddenly lost, applying full surface pressure and tubing hydrostatic to the annulus area before the pumps can be shut down.

The Ursa-Princess Waterflood (UPWF) targets the Lower Yellow sand, the main reservoir in the Mars-Ursa basin in Mississippi Canyon, about 60 miles south of the mouth of the Mississippi river in the Gulf of Mexico, USA. The Lower Yellow sand, a world class Upper Miocene turbidite reservoir, has been on production in the Ursa and Princess fields since 1999, and has been drawn down nearly to the bubble point. The waterflood is intended to increase and stabilize reservoir pressure, and to improve sweep efficiency. To accomplish this, four subsea injectors were designed and constructed to inject treated seawater at some 40,000 bbl/day each for a target life of 30 years.As the Lower Yellow reservoir was already highly depleted, unique risks were identified in the planned subsea completion operations, to be conducted from a Mobile Offshore Drilling Unit (MODU). Seawater, used as a completion fluid, was expected to be up to 4000 psi overbalanced to the reservoir, depending on the well location. This created the risk of either uncontrollable fluid level drop in the marine riser or extreme impairment to the sandface completion. In order to maintain well control with a fluid level at the surface and still deliver low skin completions, multiple design and procedural issues needed to be addressed, including:1. Control systems on the rig and riser system to prevent uncontrollable fluid level drop, 2.Perforating systems to minimize impairment in a high overbalance environment without adding undue risk to well control, 3.Pill designs that could both control fluid loss at the sand face and clean up effectively, 4.Downhole completion systems capable of functioning either under very high pressure differentials or against very high loss rates, 5.Development of high burst screens that could withstand pilling in the event mechanical fluid loss devices failed. As more Deepwater reservoirs approach depletion, specialized tools and procedures will be required to continue to deliver safe and effective sandface completions from floating rigs. This paper details many of these considerations, and summarizes the execution experience and results for one such reservoir.