TX 75083-3836, U.S.A., fax 01-972-952-9435.References at the end of the paper. AbstractA fracturing treatment is defined as treating a formation above matrix rate and pressure, i.e. above the limits dictated by Darcy's Law. Under this condition, the rock cannot take the fluid and is "split" or fractured to accept the fluid at the delivery rate. Several different acid fracturing procedures and treatments are well known and established in the industry 1,2,3 and have been used with varying success.These procedures have been applied to several acid fracturing treatments that were performed on depleted wells in the Middle East. Shortly after the treatment, very high production rates were observed. However, these production rates declined steeply after the initial improvement. This paper will describe how these treatments were improved with a systematic engineering approach and how production of the wells was quadrupled with stabilized production rates. After initial optimization of the fluids system (such as introducing density-controlled treatments), a core analysis was performed to further optimize acid concentration and chemical loading. The next step involved a buildup analysis to determine fracture half length and skin values. The analysis showed that, even though effective etched fracture lengths were obtained, a positive skin was present in the matrix along the frac length, indicating treatment fluid retention problems due to the low BHFP.Since foamed acid treatments were not economically justifiable, the readily available gas used for lifting was injected several days before each treatment. The formation was therefore supercharged and able to produce the injected fluid back out of the formation, leaving a negative skin behind.
Determination of reservoir characteristics from transient pressures created by underbalanced perforating can enable an operator to decide whether a well is commercially productive before permanent completion. Several techniques exist to analyze such data. In this work, closed-chamber testing and log-log-and Cartesian-plotted short producing times are used to analyze data collected from a multiwell project in the Gulf of Mexico. Pressure data were obtained from underbalanced perforating and backsurge-washing treatments. Results of these analyses compared favorably with buildup tests performed after the wells were completed.
This paper discusses the application of a new expandable liner hanger system in a deepwater, high-pressure, high-temperature (HP/HT) well in the Mediterranean Sea, Egypt. At the time of its application in early April 2007, it was the first expandable liner hanger set in Egypt and the industry's first, deepest set depth (4870 m) for the 7 5/8-in. liner hanger size. A majority of the liners run in this area for this operator can be classified as drilling liners that allow the well to be "cased off" at key points in the drilling sequence so that drilling can progress safely to its target depth. This case history is about setting a liner across a weak (lost circulation) zone and a high-pressure kick (saltwater) zone drilled in the same hole section. The liner hanger operation was deemed critical especially after having had an issue in the last hole section in setting a conventional 9 7/8-in. liner hanger packer resulting in 2.1 days of NPT (nonproductive time). It was important to get proper isolation of both the formations and the liner lap and the placement of the liner in the desired position to avoid having issues drilling ahead. The expandable liner hanger (ELH) offers a significant departure in design from a conventional system. The mechanics of the ELH system eliminates the potential of a premature set of the hanger. Moreover, it eliminates the normal operating procedures of testing conventional liner tops and "dressing" cement left on top of the liner—operations that require a substantial amount of time and money to accomplish before drilling ahead can resume. This paper will discuss the expandable liner system in detail with an insight into its design, operating procedures, its simplicity, and the benefits it provides even in difficult well conditions such as this case history. Introduction The liner running operations in Egypt are not much different than elsewhere in the world. They are plagued with similar incidences of liner job failure; namely:Lap squeeze-leaky lapShoe squeezeStuck liner while running inWiper plug did not release or bump.Packer, hanger, centralization, premature set, or failure to setLost circulationCementing issues The most recent problem faced in the previous hole section of this well was that the liner top packer would not set, and therefore, a test could not be achieved on the top of the liner. The setting procedure for the liner-top packer varies with different models, but essentially in a mechanically set packer, it involves engaging the "lugs" in the setting tool with the internal matching recesses of the packer assembly. Once engaged, the tool is manipulated (i.e., rotation of pipe), and weight is slacked off on the packer for its expansion. Depending on the well conditions, the engagement does not often occur in the first attempt for various reasons (e.g., LCM in the mud, barite settling, thick mud, etc), and the process can easily extend into two hours of manipulation before success is achieved. However, the concern is that cement slurry from the liner cement job is usually sitting stationary across the setting tool during the entire time. Often, this delay in setting the packer has resulted in an overpull on the setting assembly when pulling out of hole. For obvious reasons, this is a risk that can become very costly to fix. As mentioned earlier, in the previous hole section the liner top packer did not set after working on it for 2 ½ hours. The liner running tool had to be pulled out of hole, and another liner top packer had to be picked up to set on top of the failed one.
Determination of reservoir characteristics from formation pressure created by underbalanced perforating may enable an operator to decide whether a well is commercially productive prior to permanent completion. With the use of several existing techniques, it is possible to analyze such data. With closed chamber testing techniques, wellhead pressures are used to calculate variable sandface rates during and shortly after the well is underbalance perforated. Superposition is employed to create a rate-time function for plotting with bottom hole pressure data. The straight-line portion of the pressure versus ratetime function plot can be fitted using linear regression to solve the radial flow equation. Calculated parameters include effective permeability, skin effects and initial reservoir pressure. Also presented, is a method proposed by Soliman to analyze short producing time data. Delta pressure versus total time data is plotted on a Log-Log graph where the time axis combines producing time with build up time. A negative one (−1) slope on this plot indicates the existence of radial flow, from which reservoir characteristics can be calculated if the flow regime is known. A cartesian plot can be used to estimate initial reservoir pressure. This paper illustrates the use of the aforementioned techniques on data collected from a multi-well project in the Gulf of Mexico. Analyses of oil wells were investigated. The results of these analysis methods for oil cases are compared with buildups performed after the wells were completed. These analysis techniques have also been applied to formation back surge data with similar results.
TX 75083-3836, U.S.A., fax 01-972-952-9435.References at the end of the paper. AbstractA fracturing treatment is defined as treating a formation above matrix rate and pressure, i.e. above the limits dictated by Darcy's Law. Under this condition, the rock cannot take the fluid and is "split" or fractured to accept the fluid at the delivery rate. Several different acid fracturing procedures and treatments are well known and established in the industry 1,2,3 and have been used with varying success.These procedures have been applied to several acid fracturing treatments that were performed on depleted wells in the Middle East. Shortly after the treatment, very high production rates were observed. However, these production rates declined steeply after the initial improvement. This paper will describe how these treatments were improved with a systematic engineering approach and how production of the wells was quadrupled with stabilized production rates. After initial optimization of the fluids system (such as introducing density-controlled treatments), a core analysis was performed to further optimize acid concentration and chemical loading. The next step involved a buildup analysis to determine fracture half length and skin values. The analysis showed that, even though effective etched fracture lengths were obtained, a positive skin was present in the matrix along the frac length, indicating treatment fluid retention problems due to the low BHFP.Since foamed acid treatments were not economically justifiable, the readily available gas used for lifting was injected several days before each treatment. The formation was therefore supercharged and able to produce the injected fluid back out of the formation, leaving a negative skin behind.
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