This paper presents a statistical overview of water control issues currently important to Los Angeles Basin operators of high water cut, mature, turbidite waterfloods.Certain observations, analyses and conclusions may be of interest to others working with high water cut fields.Case studies demonstrate reasonable costs and economic payouts for water control efforts. Several LA Basin operators contributed water control-related information to a consortium study sponsored by the the U S DOE PUMP program and the California Energy Commission and managed by the Petroleum Technology Transfer Council.Data from seven fields, which together account for more than half of LA Basin's production, were analyzed in order to identify key factors which contribute to water control problems and solutions. Information for wells with poor or good performance were obtained from the operators and analyzed.Parameters which differed significantly among categories of injectors and producers were characterized.In total, 60 injectors and 67 producers were analyzed in detail, yielding several statistics and observations of interest. Water control strategies were also analyzed as part of this study.Seventeen water control jobs, costing $25,300 on average, resulted in an average payout of 7.1 months.Operators' policies regarding computation of water production, treatment and re-injection costs were reviewed in detail, resulting in a weighted average cost of $.23/bbl of water produced.Operators investing more than $.02/bbl in water control were observed to hold water cut increases to less than 0.2%/year, while those spending less than $.01/bbl experienced annual water cut increases in excess of 0.4%/year. All statistics highlighted above were extracted from several databases that allowed many more analyses to be conducted, including individual operator and/or field comparisons to basin-wide averages. Background Water production in oil and gas wells is a limiting factor that often determines their productive lifespans.Besides the environmental issues and cost of disposal, lifting excess water significantly increases electrical consumption and associated costs.A proper identification methodology to determine the source of excess water coupled with corrective measures to reduce water production can reduce the demand for electricity, improve oilfield economic life, and minimize environmental impacts. In the United States, California is the 4th largest state in terms of oil and gas production.More than 46,000 wells annually produce about 271 million barrels of oil and another 2.1 billion barrels of associated water[1].A previous study[2] sponsored by California Energy Commission, PTTC and EPRI-PEAC established that pumping wells, under optimum efficiency, consume about 0.5 kwhr/bbl/1,000 ft of depth.In a survey of more than 1,000 wells, it was established that more than 45% of the wells were consuming more than this optimum rate.Assuming a production rate of 2.1 billion barrels of associated water from an average depth of 2,500 ft, oilfield operators consume at least 2.1x109x0.5x2.5=2,600 GWhr annually just to produce water.This does not take into consideration the additional power consumption for injection or disposal operations.While the volume of injection and disposal may have to stay at the current levels for pressure maintenance purposes, the excess water produced may be reduced using a systems approach.Practical solutions resulting from innovative engineering can result in a significant drop in electric demand load in California. Most of the Los Angeles Basin's largest oilfields were discovered over seventy years ago, and have been water-flooded for an average of thirty years.Prolific reservoirs and prudent operating procedures have resulted in still-profitable operations in many of these fields despite water cuts of 95% and higher.Figure 1 displays a map of the LA Basin and its largest oilfields, while Table 1 contains statistics by field.
Waterflood injection wells operate at maximum efficiency when delivering maximum, non-fracturing matrix rates to highest oil water ratio (OWR) subzones. Decreasing OWR observed during the later years of a mature waterflood intensifies need for analysis and optimization of injection efficiency. Analyses of injection rates, pressures and distribution profiles, especially when combined with recently more available step rate test (SRT) data allow injector efficiencies to be quantified in terms of estimated resulting BOPD. The Los Angeles basin is home to many mature, low OWR waterfloods and a large, steadily increasing number of injection wells. In order to analyze injection efficiency over time, a prototype injection well, designed to include features common to LA basin injectors, was evaluated at key times of design, SRT, startup, profile deterioration, and finally, 100% point exit. Local DOGGR injector permitting practices were incorporated into determination of "Maximum Allowable Surface Pressure" (MASP) for the prototype well. Estimated losses of injection capacity resulting from conservative "safety" practices of frac gradient discounting and ignoring friction pressure were significant, suggesting consideration of alternative uses of SRT data. Damage/stim cycling, an unfortunately common LA basin injector operational practice, was analyzed in detail, focusing on inefficiencies resulting from damage accumulation followed by unintentional selective stimulation of lowest priority subzones. Since the industry's common goals would be advanced by a basin wide decrease of damage/stim cycling, improvements are suggested for the consideration of both operators and regulators. Operators with best record for maximizing injection efficiency reduce damage/stim cycling by maintaining appropriate water quality standards and optimized injection profiles. When coupled with aggressive production well management policies which minimize low OWR production, e.g., shutting in highest water cut wells, even very mature waterfloods have been shown to perform without rapid BOPD declines. Paper concludes with practical suggestions to accomplish DOGGR/UIC fracture-prevention goals utilizing traditional and/or modified SRT designs to generate a permitted "Maximum Allowable Rate" (MAR). In addition to avoiding unintended consequences of the traditional MASP permitting approach, waterflood management and regulation by MAR would encourage development of new technologies and operational practices.
A novel and simple sand control technology has been developed and field tested featuring a prepacked liner consisting of thermosetting resin coated sand grains bonded by heat onto a perforated steel base pipe to form a solid, porous, and permeable cylindrical sand liner that can be installed into a wells requiring sand control. The Resin Coated Prepacked Sand Control Liner is a cost effective tool that can be applied to a variety of wellbore situations requiring remedial or primary sand control. The liner does not use wire wrapping and is constructed using standard oil field tubulars and commercially available thermosetting resin coated sand. The liner fills a need in certain sand control situations that cannot be solved using conventional technology. The Resin Coated Prepacked Liner is used with and without secondary gravel packing, depending on the well and reservoir conditions. The Resin Coated Prepacked Liner is currently installed in one well in the Long Beach Field, Southern California as a field test in a problem well that has historically experienced wellbore sand accumulation and repeated pump failures. Since installation in June 2002, the well has been sand free with an unexpected increase in oil production. Introduction A new sand control technology utilizing a solid, resin coated, prepacked liner has been developed and patented that provides oil producers with an alternative tool for use in wells experiencing sand control problems. The Resin Coated Prepacked Liner has been successfully applied in the Long Beach Field in Southern California. The present state of art in conventional sand control technology includes wire wrapped screens, narrow gauge slotting capability, improved wellbore filtering, and better gravel placement methods. Though not necessarily considered conventional, some high tech equipment has also become available, including sintered metal filters, and expandable metal screens. Excluding the latter, the basic concept of sand control technology however, generally remains unchanged; that of placement of a gravel medium between the sand face and the wellbore to restrict the invasion of formation material into the producing conduit. This technique has been in use for decades, and has been very effective in accomplishing its intended objective. As with most technologies however, some limitations and shortcomings have been experienced, usually occurring in the form of loss of sand control resulting from a number of controllable or uncontrollable causes. These, to name a few, include liner slot corrosion or erosion, gravel pack voids resulting from gravel pumping interruptions, wire wrap screen tears during installation or mishandling, gravel pack contamination with formation solids due to improper wellbore fluid conditioning, and non-concentric pack placement because of poor liner centralization. A variety of other causes of lost sand control have been experienced by operators over the years, but the remedies available to improve their longevity has been limited. This paper presents a novel concept and alternative to conventional technology that was designed and developed to help solve some of the above mentioned problems, and provide some versatility for an operator to consider when faced with correcting a sand control problem well. The design, development, construction, and testing of the liner are discussed, as well as its performance in a remedial application in the Long Beach Field, Southern California (Los Angeles basin). Unconsolidated sandstone formations make up a significant share of producing oil and gas reservoirs in California, as well as many other regions in the United States. Well completions employing sand control technology are common. With these completions also come the unfortunate early or eventual problems mentioned above. Well economics and well conditions will determine if the lost production can be restored, but considering the present costs associated with full sand control repairs, it is not uncommon for these wells to be shut in permanently, or remain idle for long periods of time. If repairs can be made, they usually involve modifying the wellbore to a smaller diameter and installing a gravel packed liner. If wellbore space is restrictive, then a redrill of the well is the only remaining alternative, or abandonment if the costs of operations, repair, or redrill are excessive.
Diatomite reservoirs in the San JoaquinValley contain vast reserves in high porosity, thick pay zones. Waterflooding ~ould substantially increase recovery if ~mplemented successfully. Unfortunately the presence of fractures in a low perme~ bility matrix makes waterflooding difficult to evaluate by conventional methods. Presented here are unique laboratory methods and results of laboratory tests designed to provide operators with data to better evaluate the secondary recovery potential of diatomite.Subsidence-oriented compressibility tests revealed extreme sensitivity to standard core cleaning and drying procedures. All subsequent tests, including brine sensitivity, relative permeability, and spontaneous imbibition were performed following miscible solvent cleaning with no drying step. Spontaneous water imbibition was ~nvestig~ted in detail, showing prom~se for oil movement from the tight matrix into adjacent fractures during a waterflood.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents a statistical overview of water control issues currently important to Los Angeles Basin operators of high water cut, mature, turbidite waterfloods. Certain observations, analyses and conclusions may be of interest to others working with high water cut fields. Case studies demonstrate reasonable costs and economic payouts for water control efforts.Several LA Basin operators contributed water control-related information to a consortium study sponsored by the the U S DOE PUMP program and the California Energy Commission and managed by the Petroleum Technology Transfer Council. Data from seven fields, which together account for more than half of LA Basin's production, were analyzed in order to identify key factors which contribute to water control problems and solutions.
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