Prehydraulic fracture diagnostic pumping analysis has recently improved with the use of new analysis techniques such as G-Function derivative plots, after-closure analysis, and step-rate tests. This paper analyzes various types and combinations of step-rate injection tests from many different formations around the world to determine the usefulness of these tests. The analysis uses wells with both surface and bottomhole gauge data, and in some instances, compares the results of the two. The final results of the stimulation treatments are also compared to the prefrac analysis. While the results of these tests provide information on the presence of excess near-wellbore friction or tortuosity, what is often not taken into account is that this tortuosity often destroys the usefulness of these step-rate tests in providing much sought-after data such as accurate fluid efficiency and closure pressure numbers. The focus of this paper will be on step-up and step-down analysis, with the result being a new type of graph that provides an indepth look at the quality of these tests in any given well. Often these tests are performed and erroneously analyzed because of the effects of tortuosity, with the end result being either the data is ignored or discarded. Techniques are provided for analyzing these tests and suggestions are given to improve the results obtained from these tests. Introduction Oil and gas wells of different permeabilities and lithologies often need to be effectively fracture stimulated to provide operators with sufficient economic return on investment. In an effort to ensure that a stimulation treatment can be placed, injection tests or fracture stimulations without proppant or with minimal amounts of proppant have been employed to test a formation's capacity to receive a treatment and to help optimize the final treatment design. The design of these injection tests, usually called "minifracs" or "datafracs" is based on the type of information the operator or stimulation designer seeks. Information that can be obtained or inferred from these tests include closure stress or minimum stress, bounding stresses, fracture geometry, presence of natural fractures, permeability, leakoff coefficient, fluid efficiency, pore pressure, fracture gradient, fracture extension pressure, net pressure, and excess friction.[1–3] Variations that can be made in these tests include injection rate, fluid type, fluid loss additives, proppant type, proppant volumes and concentrations, and finally, combinations of various diagnostic injections. The order in which these tests are performed can also have an influence on the outcome of the analysis and final treatment design. One such test is the "step-up" step-rate test. In this test, injection into a formation is begun at a slow rate for a fixed amount of time, and the rate is then increased and again held for the same amount of time. This is repeated in an attempt to achieve three matrix injection rates and three fracture injection rates. A graph of rate vs. bottomhole pressure is then made at the stabilized points, and fracture-extension pressure is indicated as the point where the pressure "breaks over" or large increases in rate provide small increases in bottomhole treating pressure. As will be discussed, a plot of bottomhole pressure vs. injection rate provides a myriad of useful information, provided there is good communication between the wellbore and the formation. It will also be shown that the presence of tortuosity virtually destroys this test, and while it has been proposed that near-wellbore friction can be mathematically removed from this test, the supplied analysis demonstrates that this is rarely the case. Another rate-dependent test is the "step-down" step-rate test. It has been proposed and is now generally accepted that this test can provide a rate dependent friction value for tortuosity and perforation friction, and can differentiate between the two. The main requirements of this test are that it be sufficiently rapid, or sufficiently slow in the case of formations with very low leakoff, so that the fracture geometry does not change during the step-down test, and that a displacement fluid with known friction values or bottomhole pressure is accurately determined from a live annulus or bottomhole gauges.
SPE Members Abstract Permian Basin operators who need to seal casing leaks to pass Permian Basin operators who need to seal casing leaks to pass Texas Railroad Commission mechanical integrity tests have successfully applied small particle-sized cements, which penetrate casing cracks and very small channels to effect a penetrate casing cracks and very small channels to effect a seal. Small casing leaks plague injection operations when integrity testing results in pressure bleedoff, which indicates presence of leaks. A batch-mixed volume of 25 to 75 sacks of fine particle cement is the typical application used to seal these particle cement is the typical application used to seal these leaks. There are some critical steps that must be taken to help ensure job success; these are discussed. The paper also presents a discussion of small particle-size cements, including presents a discussion of small particle-size cements, including accounts of laboratory testing. Case histories describing techniques of casing leak repair with small particle cements are recounted. Introduction The Permian Basin area of West Texas is known for many waterfloods, H2S problems, and weak formations. The Permian Basin has a long drilling history, and it therefore Permian Basin has a long drilling history, and it therefore contains numerous old wells (up to 50 years old), the casings of which are subject to corrosion degradation. These characteristics make Permian Basin wells subject to casing leaks and cause wells to fail casing integrity tests established by the Texas Railroad Commission for injection wells. Most casing leaks in the Permian Basin that have been repaired with small particle-size cement have ranged from 2000 to 12,000 ft in depth. Most of these have been shallow repairs, 5000 ft and above with some as shallow as 100 ft. Squeeze cementing with small particle-size cement has proved to be an excellent way to seal casing leaks without requiring perforating. Small particle-size cement squeeze jobs do not perforating. Small particle-size cement squeeze jobs do not just patch the damaged area but penetrate to create a seal, Because the need to perforate is eliminated, many small particle-size cement squeeze jobs are less costly than squeeze particle-size cement squeeze jobs are less costly than squeeze jobs involving standard cement. Many successful squeeze sealing jobs using small particle-size cement have been performed in the Permian Basin, The likelihood of a successful small particle-size cement squeeze job is enhanced by incorporating certain preparatory and procedural steps advocated within this paper. procedural steps advocated within this paper. Small Particle-Size Cements There are two types of small particle-size cement available; within this paper they are referred to as "fine" and "ultrafine." Both fine and ultrafine cements are very finely ground cements with average particle sizes much smaller than standard API cement. The small particle size of these cements make them well suited for all squeeze jobs, especially casing and collar leaks in which cement must penetrate very narrow or "tight" areas. Table 1 compares physical properties of fine, ultrafine, and standard cements. properties of fine, ultrafine, and standard cements. Fine cement is a very finely ground cement with an average particle size of 8 microns and a maximum particle size of 15 particle size of 8 microns and a maximum particle size of 15 microns. Fine cement consists of 20 to 30% finely ground cement and 70 to 80% slag material. Ultrafine cement consists of 100% very finely ground Portland cement and has an average particle size of 4 microns. Its extreme fineness makes it very reactive but provides it with excellent penetration capabilities. The benefits of small particle-size cements have been proven in hundreds of jobs which required sealing a casing collar leak or other very narrow area. In these cases, traditional API cements bridge on the affected area, but small particle-size cements penetrate to provide a much more complete seal without requiring perforating. Other applications of small particle-size cements include penetration of gravel packs, particle-size cements include penetration of gravel packs, sealing highly permeable zones, stopping unwanted water or gas production in behind-pipe channels, and squeezing small channels. P. 429
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.
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.
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.
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