Steam injection is a successful operation to increase heavy-oil production, but the casing failure rates in steam injection wells are very high. Severe thermal-loading to the casing is resulted from steam injection operations and is attributed to the high casing failure rates. The casing failures can be casing parted due to fatigue and/or tensile load at cooling period, and can also be casing ID restriction due to collapse and/or severe buckling. This paper will briefly review the common casing design practice, and provide mathematical modeling of casing stresses in steam injection wells, and discuss ways of reducing casing failures, including the use of high strength casing (such as P-110 grade) to reduce casing hot-yield in most steam injection wells. The field data at Cymric 1Y field, Bakersfield, California are also presented to support the use of high strength casing (P-110 grade) in steam injection wells, based on the reduction of casing failures in the past two years. Introduction It has been common practice in the oil industry for many years to use low-strength casings (K55, N80, and L80) in steam injection wells, despite a higher casing casing failure rate thaninconventional wells. Previous studies have shown that when low strength casing is well-cemented, the support of the cement may prevent casing failures (buckling and collapse),[1,2] even when the casing is hot-yeilded under extreme axial thermal compressive load during stream injection period. Of course, the support of the cement cannot prevent the low strength casing failure under tension load during soak or production. As shown in Fig. 1, the common steam injection practice recognizes that the casing axial compressive stress increases with the starts of steam injection and the casing becomes hot-yielded at curtain temperature.After the casing is hot-yielded, the casing axial compressive stress remains the same (Dietrich-Whillhite model) or reduces slightly (Material work hardening model), as the temperature continues increasing. But with the support of cement, the casing does not fail due to hot-yielding during steam injection. Instead, the casing fails in tension during soak or production period, when casing temperature drops and axial tension stress develops and reaches the casing material yield strength. However, a well-cemented casing condition is not always achievable or maintainable in cyclic steam injection wells. Poor cement jobs can result in no or poor cement outside sections of casing; cement fall-back at the end of cement pumping can leave the top casing section uncemented; perforating may cause damage to cement near the perforations; cyclic steam injection may fracture the cement. Those may explain why the casing failure rate has been very high in steam injection wells. The casing can fail under hot-yield period in axial compression due to insufficient cement support, or under the cold-yielded period in axial tension no matter whether cement is good or not. The casing failures related to hot-yield include casing ID restriction due to collapse and/or severe buckling. The following table shows the casing temperatures that could cause casing hot-yield in compression for different grades of casing. The initial temperature is assumed to be 15 oC (60 oF) and the initial casing axial stress is assumed to be zero. Casing material yield strength reduction at high temperature is included. It is seen that low strength casing material K/J 55 and N/L 80 will all become hot-yielded, when casing is heated-up to a temperature of 400 F. deg. which is lower than steam injection temperatures in most steam injection projects. Table 1.Casing Grade Hot-Yield Temperature
One of the simplest ways to increase production from a well is to optimize the pumping unit. A properly sized and configured pumping unit lifts the maximum barrels of fluid that the well is capable of producing while minimizing the wear on the rods and pump. Optimization is usually done through the use of software such as RODSTAR or ECHOMETER on a well-by-well basis. The user must input all the well parameters by hand, causing it to be a long and tedious process. This makes overall field-wide optimization extremely time-consuming for fields in which there are many wells. Moreover, the software determines theoretically the most optimal unit configuration for the well and may recommend a unit that is not readily available in the area. This paper describes a new approach for field wide pumping unit optimization. The methodology described here uses a neuro-system consisting of a neural network and an intelligent swapping procedure to find the optimum pumping unit placement for the field. Since field data is used in the model, only pumping units readily available in the field are used. This method is suitable for any field with pumping wells, especially those fields in which there are many wells, thus allowing the selection of a confident data set. Criteria and constraints are set to select the wells that are currently sufficiently optimized. These wells are used as the model data to train a confident neural network. Optimum pumping unit sizes are then predicted for those wells that are considered to be non-optimized. Finally, an intelligent swapping procedure is invoked to swap over- and under-sized units, thus providing field wide optimization. The final goal of this study is to provide a tool that allows engineers to set acceptable, realistic criteria to optimize pumping unit size for each well and pumping unit placement on a field-wide basis. The paper presents an example of methodology applicability to a Chevron-operated oil field in California. The proposed procedure provides confident results, great flexibility, and fast optimization. Introduction Rod-pumped production is one of the oldest and most practical methods of producing reservoirs. It is still wildly used today in many fields. However, to produce the maximum amount of fluid, the pumping unit must be optimized for the potential of the well. Pumping unit optimization has become a necessity for the industry. As a result computers programs such as RODSTAR and ECHOMETER are used to help in the selection of the best unit to fit the production potential of the well. This is oftentimes not a very practical approach since the suggested unit may not be available in the field. As a result, a similarly sized unit will be placed on the well. To compound the problem, the potential of a well is always changing over time due to factors such as depletion, formation damage, stimulations, and workovers. Even if the pumping unit has been optimally sized at initial completion, the well may likely become non-optimized over time as the potential of the well changes. The problem addressed in this work is field wide pumping unit optimization using only the available units in the field. In other words, finding an optimum placement combination of the units existing in the field for currently non-optimized wells. Usually pumping unit optimization is done one well at a time. This well-by-well optimization is time consuming and requires a certain amount of specialization for this kind of task. Moreover, a human being can only perform a simple swapping procedure. Usually this is no more than the simple exchange of units between two wells. Complex swapping scenarios to optimize the entire field are not possible by these means.
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