Petroleum Development Oman (PDO) is producing substantial amounts of unwanted water or gas from most of its oil fields. To increase recovery from maturing reservoirs, PDO is developing the capability to detect and shut-off unwanted water and gas. Swelling elastomers have been deployed to segment horizontal wells in combination with surveillance and shut-off technologies. In beam pump wells dual wellheads have enabled logging while pumping. A key element to achieve improved oil recovery through well and reservoir management in a horizontal well is segmenting the well into different flow units. Swelling Elastomers (SE) are being deployed to enable segmentation. SE tool provides zonal isolation through the swelling of the elastomers when contacting produced water in the wellbore. In clastic reservoirs the completion philosophy has been changed from drilling minimum functionality wells to wells with closed-annulus completions that allow for surveillance and interventions. Surveillance is done in the drilling phase with under-balanced drilling and other open hole logging measurements. In the work over phase unwanted flow segments have been detected by logging while pumping coupled with greater integration of available reservoir data. Mechanical segment shut-off methods have been used. To date PDO has segmented more than 100 horizontal wells with swelling elastomers. In more than 20 wells suspected water producing feature were isolated at the initial completion stage and the rest were segmented based on reservoir flow unit characterization. After having proved that SE is delivering value in initial water shut off, the strategy is to prove a viable surveillance technique to identify water entry point in horizontal wells, and to develop several reliable water shut off (WSO) techniques depending on which segment's to be closed and if reversibility is required. To date more than one million barrels of oil have been realized as a result of the initial isolations as well as subsequent water shut offs. This paper is a continuation to the work presented in SPE paper number 91665 and will present case histories of the delivery and management of wells with swelling elastomer in clastic reservoirs in Oman. Introduction The South fields are located in southern Oman is in fact a group of six fields. Most of them are mature oil fields operated by Petroleum Development Oman. The fields produce medium gravity viscous crude with viscosity ranging from 200–550 cp. Reservoir pressure is maintained by infinite bottom water drive. The fields have been producing since mid 1980's. Initial fields' development was via vertical wells however, since the mid 1990's development has been primarily with horizontal wells. Production is from a combination of Aeolian and glacial sediments. Reservoir heterogeneity is high especially in the glacial Alkhalata reservoir. These fields accounts for more than 10% of total PDO production and is produced from almost 500 active wells. The current field water cut is about 93%. South field wells have different design. Almost all South field wells must have sand control. The horizontal reservoir section is about 350–500m long. The horizontal section may cross both reservoirs (Alkhalata and Aeolian Amin reservoirs). The horizontal section is drilled with a 61/8" drill bit and completed with stand-alone 4½" sand control liner using 200 micron wire-wrap screens (WWS) in open hole. This results in an open annulus between the sand control liner and the formation. More than 90% of well are artificially lifted via beam pump (BP) hence hindering accessibility due to surface units and rods. In the early development phases it was assumed that water production is simply a result of conning, and water is produced through matrix and all faults fractures are assumed to be sealing. However since the start of infill drilling in 1999, the new oil production has been historically dominated by high initial BSW levels and as of 2002 new wells produced cumulative average of three barrels of water for every one barrel of oil during their first year of production.

fax 01-972-952-9435.This paper will present case histories of the profiling technique along with results and conclusions. It will also compare the response from this technique to normal production logging.

Polymer outage (or polymer injection unavailability) is undesirable but also inevitable. When it happens, the question is how to respond to it to minimize its adverse impact on the production. This paper presents the rationale for generating a polymer outage strategy to operate a polymer flood field in the southern area of the Sultanate of Oman. The work presented here is based on field performance and analytical analysis. The diagnostic plots were created from 10 years of polymer flood field response and were used for this operating decision. The pros and cons of two scenarios were discussed. The selected operational strategy is to minimize the short falls of polymer outage. The strategy was implemented in the field. Simultaneous injection and production pause (SIPP) is recommended for the full field polymer outage. It minimizes the impact on polymer incremental oil and hence less deferment. Calibrated with the actual results, analytical method is used to determine when to shut down and whether a short of buffer period of water can be tolerated before SIPP is carried out. The polymer literature focus on polymer mechanisms, modeling, project initiation and implementation but no paper discusses the operational strategy on how to respond to field polymer outages. This paper shares our operational learnings and the field results of various polymer operation modes on polymer incremental oil. The learning from this field may be of interest to other operators who are planning or currently implementing polymer flood in their fields.

Petroleum Development Oman (PDO) has commenced several Enhanced Oil Recovery (EOR) methods in the Sultanate of Oman to increase recovery from fields with challenging rock and fluid properties. Polymer flood is one of the mature EOR techniques that are currently operated in sandstone reservoirs in the South of Oman. The reservoir under trial in this paper shares its OWC with another reservoir that has been developed through polymer flood. Although they both share similar fluids with viscosity of ~90cP, the reservoir under trial exhibits significant lower permeabilities, which poses a risk to injectivity. Furthermore, well completions with sand control have shown to be too detrimental to productivity which causes high sand production. This creates a challenge for the polymer flood from both the injectivity and sand control point of view. Thus, a pilot was designed with the following three objectives; test ability to sustain injectivity of polymer into the reservoir, monitor polymer efficiency, and evaluate operational impact on facilities due to sand production that is expected to increase with polymer flood. The pilot was designed such that two patterns are drilled adjacent to each other where one will be used for the polymer flood and the other pattern serves as a backup in case the first pattern suffers from loss of injectivity or any unforeseen issues. The patterns are inverted five spots with an injector-producer spacing of 75m. The injectors are equipped with fiber optics for data acquisition and real time temperature and acoustic surveillance. The plan is to inject water until a baseline is established, which is then followed by polymer injection for up to one year. Currently, the project is in the water injection phase where information and data are gathered such as injectivity, conformance, reservoir connectivity in addition to fluids production baseline establishment. This paper presents those findings from the water injection phase in addition to design aspects for the polymer phase.

Polymer flood as a mean of enhanced oil recovery was applied in a large sandstone heavy viscous (22API & 90cP) oil field located on the South of the Sultanate of Oman. The polymer flooding was commenced in 2010 with phase I covering 27 patterns, by means of inverted 9-spot pattern. In 2015, Phase I was followed by Phase II with additional 19 patterns. Full field polymer flooding is planned in the coming years. Over 250 oil producers are benefiting from changing the recovery mechanism water flooding system to the increased viscosity flood system (polymer). Significant oil gain was achieved by improving the recovery factor. Around 92% of the total wells in the field are completed with the two main artificial lift systems, beam pumps BP and Progressive Cavity Pump PCP. After circa three years of introducing the polymer flooding in the field, new trend of well failure rate was observed in which the artificial lift failure rate was increased by around 40% by end of 2014. This has massively increased work-over job frequencies and cost, and has significantly increased the crude oil production deferment. New type of failure mode was seen in the sucker rod and tubing of the BP & PCP. Severe eccentric wear of sucker rods and tubing in many vertical wells with pumping unit have accrued in which the coupling was worn out and broken from one side i.e. most of phase I & phase II wells experienced premature or frequent failure. By end of May-2015, 83% of failure were associated to pump failures and it is more related to well conditions. Material analysis of the damaged sucker rod & plungers were conducted & the failure mechanism of both parts of the beam pump was investigated. Around 73% of the pump failures were found to be due to solids handling (sand, scale solids) & corrosion issues or combination of both, erosion & corrosion mode of failure. On the other hand, around 60% of rod failures of the polymer flooded wells were due to wear. Set of trials and initiatives were conducted to improve the sucker rod run life and reduce the failure rate. For example, centralized molded sucker rod, continuous rod (pro-rod), GRE lined tubing and long stroke pump (roterflux). Some good success was achieved in arresting the failure rate and improving sucker rod run-life. Material analysis studies & trials were also conducted to improve the barrel life. Evaluation of the various trails are currently ongoing and still at early stage to draw clear conclusions. This paper will discuss the material analysis studies and the main practical trials that were conducted to reduce the pump and rod failures, and therefore improve well run-life in the field.