A case history from Offshore Israel is presented that describes the successful delivery of two (2) ultra high-rate gas wells (+200 MMscf/D) completed in a depleted gas reservoir with 9⅝ in. production tubing and an Open-Hole Gravel Pack (OHGP). Maximizing gas off-take rates from a volumetric drive gas reservoir that possess high flow capacity (kh) require large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of wells completed with 9⅝ in. production tubing ("big bore") determined that this design concept was feasible and deliverable in a short time frame while still maintaining engineering rigor. The paper will highlight key accomplishments within various phases of a completion delivery process for critical wells. The completions were installed with minimal issues (NPT≈ 9%) and have produced without incident. The wells are capable of +250 MMscf/D and are currently producing at +220 MMscf/D.
A case history from Offshore Israel is presented that describes the successful delivery of five (5) ultra high-rate gas wells (+250 MMscf/D) completed in a significant (10 TCF) gas field with 7 in. production tubing and an Open-Hole Gravel Pack (OHGP). Maximizing gas off-take rates from a gas reservoir with high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of ultra high-rate gas wells was made to select and finalize the design concept after which the commensurate engineering rigor was applied. This paper will highlight key accomplishments within various phases of a completion delivery process for critical wells. The completions were installed with minimal operational issues (Average NPT 4%). Production commenced on March 31, 2013 without incident thus far. Each well is designed for production rates in excees of 250 MMscf/D. SPE 166368 Project Statement of RequirementsGeneral. The Tamar field is the only local source of natural gas to Israel, a country with a total population of ~7.9 million people. With five (5) wells producing from the Tamar field, each well is required to provide gas to ~1.6 million people, roughly the population of the U.S. state of Hawaii. With so many people depending on each Tamar well, delivering wells with the highest reliability and longevity became the key goal of the basis of design and all subsequent decision making. Phase I of the Tamar project was designed for a maximum flow rate through the subsea system and the platform of 1200 MMscf/D. To meet this flow rate, five (5) wells capable of producing 250 MMscf/D each were required with the completions to be finished by year end 2012. To ensure the wells were cleaned up and had the necessary productivity to meet Phase I deliverables, it was required to unload and produce the wells up to 120 MMscf/D to the drilling rig immediately following the completion.Key Project Deliverables. Drill and complete five (5) wells each capable of safely and reliably producing gas at rates of up to +250 MMscf/D for 25 years. Completion Guiding PrinciplesA set of completion key performance indicators (Table 1) and guiding principles ( Table 2) were developed to guide the decision making process for the completion design. These principles were largely based on learnings from other successful high-rate gas well developments and the key project deliverables defined above.
A case history from Offshore Israel is presented that describes the successful delivery of two ultra high-rate gas wells (>200 MMscf/D) completed in a depleted gas reservoir with 9⅝-in. production tubing and an openhole gravel pack (OHGP). Maximizing gas off-take rates from a volumetric drive gas reservoir that possesses high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of wells completed with 9⅝-in. production tubing ("big bore") determined that this design concept was feasible and deliverable in a short time frame while still maintaining engineering rigor. The paper will highlight key accomplishments within various phases of a completion delivery process with particular emphasis on the sand control design, testing and execution. The completions were installed with minimal issues (NPT ≈ 9%) and have produced without incident. The two wells, Mari-B #9 and #10, achieved a peak gas rate of 223 and 246 MMscf/D, respectively.
Gas lift optimization is fundamental to protecting base production in oil fields worldwide. With real-time wellhead surveillance and automation data available on a portable laptop computer, the engineer can quickly identify well problems and opportunities to improve gas lift performance. A continuous gas lift automation and wellhead surveillance system was installed on the Amberjack field in the Gulf of Mexico and realized a 7% increase in production. This paper will discuss the problems engineers experienced understanding daily production variance before automation was installed, the system functionality of the automation system, and the results of increasing base production by 7%. Project execution is also discussed because of its importance in ensuring the offshore personnel were engaged with the project. Introduction The Amberjack oil field is located in the Gulf of Mexico, 18 miles offshore from Venice, LA. in Mississippi Canyon blocks 108, 109, and 110. Developed in 1991 as a single jacket platform in a water depth of 1030 feet, the field has 34 dry tree wells, six of which are dual completions. Production rates at the time of automating the gas lift system were 9000 BOPD, 16,000 BWPD and 20 MMcf/D. Of the 34 wells, 27 of them utilized gas lift injection to facilitate flow, representing seventy eight percent of the total production. The average depth of the wells is 6500 feet TVD in the Pleistocene sandstone with oil gravities ranging from 27° to 32° API. Before automation, the daily operation of Amberjack was a challenge for engineers. Production engineers and offshore operators spent large amounts of time simply gathering the necessary well and facilities data to understanding individual well performance. Understanding overall production variance and explaining it to management was not an easy task since morning report data was gathered by hand offshore and was always one day old by the time it was available for analysis. The gas lift automation project was a solution to the daily struggle of gathering enough data to understand field production. Automation equipment and software were put together in a combination that allows engineers and operators to measure and monitor well information and control each well's gas lift rate. With automation, each well can be monitored in real-time from the engineer's laptop computer anywhere in the world. What previously required three or more days of analysis can be accomplished in real time on a laptop from a dial-up or network connection. Background Before installing the automation system, production optimization and field management was very challenging because of the nature in which gas lifted wells flow, the number of gas lifted wells, compression constraints for low pressure gas and the overbooked well testing schedule. During 2001 the facility effectively had one test separator available for individual well testing. The second test separator was dedicated to three wells with a separate royalty interest and could not be used for individual well testing. Manual Surveillance and Optimization The well surveillance and optimization efforts in the field prior to adding the automation system were performed using data gathered completely by hand. A daily report in Excel® format was e-mailed from the field every morning at 6:00 a.m. to the engineers in the office containing field data including the following information from the previous day:Flowline pressure and temperature.Casing pressure.Gas lift rate, measured twice a day.Well tests performed and completed.Field production rates
With the continued discovery of large gas fields worldwide that have highly prolific sandstone reservoirs, the ability to design wells capable of recovering ultra-high volumes of gas will become of great interest. The project teams for these fields will be challenged to develop the fields with the smallest well count possible. The results from this study could prove useful to production and completion teams supporting large gas field developments. This paper presents a study to determine the feasibility of a subsea sand control gas well producing at rates up to 500 MMscf/D and recovering one trillion cubic feet (Tcf) of gas. Because the size of recent gas field discoveries is so large, reservoir simulation models will show that recoveries exceeding one Tcf are possible from a single location. Considering the huge cost to install deep water subsea sand controlled wells, reducing the total well count necessary to deplete the field is a business imperative. The results of the study show that completing a sand control well that can produce 500 MMscf/D and recover one Tcf is plausible. The details of the well productivity, completion design concepts and relevant comparison of analogue fields is shown. In conclusion, production and completion engineers involved in development of mega gas fields should at least consider planning for such wells.
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