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Chen, Kyle (Baker Hughes Incorporated) | Lee, Erik (Baker Hughes Incorporated) | Duncan, Roger (Baker Hughes Incorporated) | Howard, Jesse (Baker Hughes Incorporated) | Denney, Tommy (Baker Hughes Incorporated)
Lower Tertiary reservoirs are characterized by high temperature and pressure, but low drive energy due to compaction and cementation. Primary recovery factors are expected to be low and enhanced recovery through waterflood is an anticipated recovery strategy.
Design and implementation are constantly changing throughout the life of a field with the desire to converge to an optimal solution as data is gathered and models are refined. Accurate input of production and injection allocation history reduces the need to rely on assumptions and generates more productive designs, faster. Lower Tertiary fields can see particular benefit due to the fact that there are a relatively large number of geologic unknowns, uncertain injector/producer connectivity, and relatively high vertical heterogeneity.
Highly heterogeneous vertical geology and poor communication suggest the need for high spatial resolution measurements. Wireline spinner surveys require mobilization and intervention costs that limit their utility in deep water applications. However, fiber-optic surveillance has the potential to provide the necessary information. Permanently installed fiber-optic systems can enable equivalent surveys to be conducted with in-situ equipment, on-demand, for the life of the asset. This will have a substantial impact on the cost to obtain data, significantly improve measurement frequency, and reduce the time required to implement changes that improve recovery rates. Even small relative changes in the recovery rate can translate into substantially improved project economics. Optimizing the enhanced recovery process with fiber-optic surveillance provides this opportunity. A wide range of fiber optic sensing applications have been evaluated and employed throughout the oil and gas industry. In this paper, an overview of fiber optic sensing applications will be discussed and their use in Lower Tertiary reservoirs will be evaluated.
Abstract Profitability is normally maximized from oil and gas properties when maximum production rates are consistently obtained. The computer program discussed in this paper has been developed to help small operators realize that goal with minimal time investment. Introduction This paper describes a software application that enables users increase field profitability by analyzing monthly oil and gas production rates. Profitability is almost always increased from oil and gas properties when maximum production is obtained from every well. However, many managers charged with maximizing well performance do not have time to properly monitor each well to ensure production is maximized at all times. This project addresses this problem with the development of a user-friendly computer program that compares actual production volumes to forecasted production rates and alerts the user to wells that fall short of forecasted rates. The case study is comprised of 250 wells located in the State of Ohio. This group contains examples of wells that have under-produced at various times because of failure to detect and respond to decreases in production. This program, called Priority, helps users quickly identify opportunities to maximize field profitability. By comparing actual oil and gas production volumes to forecasted producing rates for a specific production period, the program generates a discrepancy report which can rank the wells in order of the greatest production deficiency to identify wells that require attention. The program utilizes production forecast information imported from commercially available reserve/evaluation software, but can also be utilized by companies that have access to spreadsheet software only. This project was specifically developed for small operators in a cost sharing venture between James Engineering, Inc. and BDM-Oklahoma under the requirement entitled, "Research and Development by Small, Independent Petroleum Operators to Provide solutions towards Production Problems." BDM-Oklahoma is the management and operating contractor for DOE's National Oil and Related Programs under prime contract DE-AC22-94PC91008. The program will be available on the National Petroleum Technology Office (NPTO) Website (); the DOE program is under the supervision of Dr. Betty Felber. Historical Monitoring Methods After years of performing reserve evaluations on thousands of wells for numerous operators, experience indicates that operators often struggle to maintain maximum well production rates. Many operators monitor well performance but fail to achieve maximum production rates consistently. Current monitoring methods and their deficiencies are reviewed below. The simplest method relies on the pumper to report decreases in production. This method often fails because pumpers are burdened with day-to-day activities and have insufficient information to develop a long-term production perspective. Therefore, many times gradual declines in production are not observed. A second method consists of a tabular comparison of current monthly production to the previous month's production. This type of monitoring employs too short a time period and does not establish a production goal. Gradual declines in production can again be easily missed. Another method employs a percentage rule. To identify problem wells, the monitoring system compares current production to the previous month's production but does not take action unless the downward variance exceeds, for instance, 10%. This type of monitoring again employs too short a time period and also does not establish a production goal. The 10% example above would allow a well to decline 5% each month over a period of time and have a significant production loss without tripping the percentage limit. P. 181^
Abstract In an offshore Abu Dhabi field, two main reservoirs are produced commingled. Monitoring the production contribution from each reservoir was previously achieved through either Production Logging or Selective Production Tests. This paper presents the successful introduction of Geochemistry as an alternative tool. This well known technique is based on the analysis of high resolution gas chromatograms of wellhead oil samples. With the help of a dedicated software pairs of peaks are selected, for which the height ratio is significantly different between oil samples of different reservoirs. The split in a mixed oil sample is then derived from the value of these peak ratios. Oil from each reservoir of the field was analyzed, and the two main reservoirs produced commingled were found to have a clearly different signature. A set of samples from commingled wells was then analyzed. The calculated oil splits were found in excellent agreement with values obtained from recent production logging data. The method was successfully extended to the case of wells producing three commingled reservoirs. It is now intended to routinely use this technique, with the following advantages:–Cost effectiveness, –No well intervention or loss of production, –The only applicable method on wells where downhole access is impossible due to mechanical problems, –Valid information even if communication behind casing exists between the two reservoirs. Introduction Petroleum geochemistry has been mainly directed towards exploration applications, such as source rock identification, oil-oil and oil-source rock correlations, maturity determinations, etc. The use of geochemistry in development geology and production engineering has however been gaining momentum over the last decade, with the following proven applications: reservoir continuity/heterogeneity determination, reservoir fluid identification (gas/oil/water), and production allocation (e.g. Kaufman et al., 1987, 1990; Baskin and Jones, 1993; Hwang et al. 1994; Baskin et al., 1995; ten Haven and Preston, 1995). The successful application of geochemistry for production allocation which is presented hereafter was initiated at the end of 1995. The field, located offshore Abu Dhabi comprises 7 reservoir units containing distinct reservoir fluids, as determined by previous PVT studies. Each of these units may in turn be divided into several sublayers, separated by sealing interzones. A schematic of these reservoir units is shown in table 1. In particular, the Upper Arab reservoirs (Arab A, B+C and D1) are produced through gas-lifted single completions with two or three zones, allowing selective production of each reservoir unit. However, for maximum productivity, most of these wells are producing commingled with all zones open. At end 1996, 22 wells are producing from the Upper Arab, 14 of which producing commingled from B+C and D1, and two others from Arab A, B+C and D1. In addition, three wells are producing commingled the THAMAMA reservoirs. Regular monitoring of the production allocation per reservoir was achieved by means of Production Logging (PLT) or Selective Production Tests (SPT). A SPT consists in closing successively the lowermost zone(s), while performing a bottom hole flowing pressure measurement at each step, as well as a pressure build-up in the closed zones. The fluid split (oil and water) for each reservoir is then reconstructed, assuming a linear IPR relationship for each reservoir. The typical PLT or SPT frequency achieved in the past was one every 2 to 3 years. Monthly production is then allocated by assuming that the total liquid split between the reservoirs remains constant, and that the water cut increases equally for all reservoirs. P. 395^