Enhanced Recovery Scheme Research Articles

The Effect of Clinical Pathways for Bariatric Surgery on Perioperative Quality of Care

Bariatric surgery demands a multidisciplinary approach and enhanced recovery schemes. Such schemes are complex and cumbersome to introduce into practice. This study evaluates if a clinical pathway (CP) facilitates implementation of an enhanced recovery scheme in bariatric surgery with the goal of improving perioperative quality of care. We compared 65 consecutive patients who underwent bariatric surgery in 2009 and were treated with a CP (CP group) with 64 consecutive patients treated without CP in 2007/2008 (pre-CP group). Process quality indicators were catheter management, postoperative mobilization, spirometer training, vitamin B supplementation, diet resumption, intake of supplement drinks, and length of stay. Outcome quality was measured through morbidity, mortality, re-operations, and re-admissions. In the CP group, foley catheters were removed earlier (p < 0.0001), patients were mobilized more often on the surgery day (CP group 92.3% vs. pre-CP group 78.1%, p = 0.03), used spirometers more often (56.9% vs. 28.1%, p = 0.002), were more often supplemented with vitamin B (100% vs. 31.3%, p < 0.0001), and received oral supplement nutrition more often (100% vs. 59.4%, p < 0.0001). Median length of stay was shorter in the CP group (6 vs. 7 days, p = 0.007). There was no significant difference in mortality, morbidity, re-operations, and re-admissions. Following implementation of an enhanced recovery CP for bariatric surgery, several indicators of process quality improved while outcome quality remained unchanged. A CP seems useful for optimizing treatment of bariatric surgery patients according to enhanced recovery principles. However, future studies are required to better determine which elements of care can be improved most.

Many small steps to reducing length of stay: A visit to the DH pilot enhanced recovery scheme

Enhanced recovery (ER) is one of the current buzz terms in the health service but it seems to mean a different thing depending on to whom you speak. The Department of Health (DH) invited applications from acute trusts across England to become 'innovation sites' for the enhanced recovery programme. These sites are supported by DH as they implement a defined programme that aims to improve patient experience through shorter hospital stays. The Bulletin spent a day at one of them, West Hertfordshire Hospitals NHS Trust, to witness the changes made.

Application of Reservoir Geology to Enhanced Oil Recovery from Upper Devonian Nisku Reefs, Alberta, Canada

The Upper Devonian West Pembina reef trend of west-central Alberta contains recoverable reserves of over 79 × 106 m3 (500 million bbl) of oil and 1.4 × 1010 m3 (500 billion ft3) of gas within approximately 50 pinnacle reefs in the Nisku Formation. Although the oil is saturated with gas at original reservoir pressure, primary depletion would soon lower the reservoir pressure below the bubble point, decreasing recovery. Thus, pressure maintenance is applied early in the producing life of the pools through waterflood or miscible flood schemes. Selection of the appropriate enhanced recovery scheme depends upon the internal flow-unit geometry of the reefs. The Bigoray Nisku C pool and the Pembina Nisku L pool for end members of the reservoir spectrum. They can be used as flow-unit models in the geological input for reservoir simulation studies. The Bigoray Nisku C pool is dominantly limestone. The primary textures, well preserved in this reef, provide the key to interpreting the relict textures in fully dolomitized reefs. A well-displayed ecological zonation of rugose corals passes vertically upward into laminar stromatoporoids, which, in turn, pass into solenoporacean algae. The coral and stromatoporoid zones each contain two generic flow-unit types, depending upon the presence or absence of dolomitization. The incipient reef facies and the algal cap with associated tidal-flat sediments represent two additional flow units. Due to the presence of horizontal permeability barriers associated with the limestone lithology, the pool is developed with a waterflood displacement scheme. Ultimate recovery is estimated to be on the or er of 0.55 × 106 m3 (3.5 million bbl) or 46% of original oil in place (OOIP). The Pembina Nisku L pool is a completely dolomitized reef, representative of the majority of the reefs in the Nisku fairway. In contrast to the Bigoray Nisku C pool, the complete dolomitization reduces the number of generic reservoir flow units observed in the L pool reef from six to three. Due to the excellent reservoir quality and absence of horizontal permeability barriers, it is being exploited by a vertical miscible flood. The Nisku L pool is one of the largest pinnacle reefs discovered in the Nisku reef fairway and contains an estimated 5 × 106 m3 (31 million bbl) OOIP. Ultimate recovery is estimated to be approximately 4.1 × 106 m3 (25.8 million bbl) or 82% of OOIP.

Design Considerations For Dome's David Alkali/Polymer Flood

Abstract An alkali/polymer flood has been designed for the David Lloydminster ‘A’ pool in east central Alberta. The David Lloydminster ‘A’ pool was originally under waterflood from November 1978 to March 1986 and approximately 30% OO1P has been recovered. Laboratory tests were initially done which showed incremental oil recovery through the use of 2% wt caustic. Further laboratory test done by Surtek Inc. of Golden, Colorado showed increased oil recovery through the use of alkali in conjunction with polymer and surfactant. This paper presents the results of the lab tests as well as the facility design for an alkali/polymer injection system. The progression of the process from straight caustic injection to sodium carbonate/ polymer to sodium carbonate/polymer/surfactant will also be described. Introduction The David alkali/polymer project is located in Sections 2 and 11–41-3-W4M approximately 100 km south of Lloydminster, Alberta. The pool is in the Lloydminster formation, which is an unconsolidated (partially cemented) sand of the Upper Cretaceous period, located at a depth of about 750 m KB. The average net pay is 3.2 m with an initial oil saturation of 73%. Porosity average 29% and the OOIP is 1.35 million m3? Reservoir fluid properties and other reservoir data are shown in Table 1. Initially the David Lloydminster ‘A’ pool was under primary operations from 1969 to 1978 and approximately 6.3% of the OOIP was recovered. In 1978, a waterflood scheme was initiated and continued until March 1986, when the infill drill program was completed and 50ft water injection began. Figures 1 and 2 show the production history for the project. In December 1983, Dome Petroleum submitted an application to the ERCD for an Enhanced Recovery Scheme which involved injection of a 2 wt % caustic (NaOH), 0.5 PV slug and Infill drilling 22 wells. A 0.1 PV slug of soft water (preflush) was to be injected to condition the reservoir prior to caustic injection. A post flush of 0.2 PV of soft water was also to be injected and a total project life of six years was anticipated. In August 1984, Dome Petroleum received approval from the ERCB to proceed with the experimental scheme. As a result of falling oil prices the economics of the project were reviewed and it was decided to drill only 13 of the proposed 22 wells. Figure 3 shows the pattern arrangement indicating the original 12 wells and the new infill wells. Drilling of the infill wells began in December 1985 and was finished in January 1986. Well 13D-2 was cored for further lab studies. Flowlining of the project and construction of the soft water facilities and battery expansion were completed in February 1986. In March 1986 the soft water injection began at a rate of 630 m3/d into the seven injection wells. Voidage replacement ratio for the project was approximately one. Encouraging results from chemical/polymer lab studies done on Dome's Cessford and Grand Forks projects as well as finding from other papers(l,2,3) led to further investigations on the David Lloydminster ‘A’ pool.

Enhanced Oil Recovery Design For The Pembina Cardium Field

Abstract The design of a hydrocarbon miscible flood is presented for areas of file Pembina Cardium field where there is little or noonglomerate present. A procedure for describing the reservoir for use in simulation is also discussed. The indicated optimum miscible flood design is to infill drill to 8-hectare well spacing and to inject at a solvent-water ratio of 2.5. A solvent slug size in the range of 10% HCPV, followed by about 20% HCPV of chase gas, is recommended. Introduction The Pembina Cardium oilfield is located 120 kilometres southwest of Edmonton, as shown in Figure I, and is the largest oilfield in Canada, covering an area of 1900 square kilometres. It has an original oil-in-place (OOIP) of 1.2 billion cubic metres and approximately 70% of the reservoir is being water flooded. The average water flood recovery is about 23%(1). This low recovery and high OOIP combine to make the Pembina Cardium reservoir a significant target for enhanced oil recovery. A study was undertaken to identify areas favourable for miscible flood implementation, to analyze their potential and the parameters which control miscible flood performance, to determine the most favourable conditions, and to evaluate the resulting economics. This paper describes the design of an enhanced recovery scheme suitable for the parts of the Pembina Cardium field that have little or no conglomerate present. It includes the description or the reservoir for use in simulation and the evaluation of various factors in the operation of the proposed EOR scheme. Nature of the Reservoir The Cardium formation in the Pembina area has been divided into four zones(2), as shown in Figure 2. Zone 1, at the top of the section, is a conglomerate which varies in thickness and reservoir quality. Its permeability can vary from 1 mD in thin deposits to more than 1 Darcy in thick, well-developed areas. Zone 2, a sandstone, is one of the two main producing zones. It is present in the central and eastern parts of the field. The third zone is a bioturbated sand-shale which is usually not productive. It isolates Zone 2 from Zone 4, which is the other main producing zone. Zone 4 is also a sandstone and ispresent in the west-central portion of the field. Figure 3 shows the areal extent of Zones 2 and 4. Kerr(3) has correlated fluid properties with geology and has established the presence of two distinct fluid, a low bubble point oil in Zones 1 and 2 and a higher bubble point oil in Zone 4. The properties or these two oils, as used in this study, are shown in Table 1. A directional flow trend, oriented southwest to northeast, has been described by McLeod(4) and Hassan(5). This trend may be the result of directional permeability within the reservoir rock or, more probably, may be the result of induced fractures oriented southwest to northeast. Virtually all of the Pembina Cardium wells are hydraulically fractured upon completion and fractures may also be induced as the result of injecting above formation parting pressure.

Facies and Porosity Distribution, Swan Hills Reef Complex, Snipe Lake Oil Field, Alberta, Canada: ABSTRACT

All of the 11,700 ft (3,566 m) of core in this 130-well limestone reef oil pool was logged for a proposed miscible flood enhanced recovery scheme. The textures, fauna, porosity types, cements, and exposure surfaces are well preserved. Selected examples of each are presented by colored slides. Nine sedimentary facies and eight porosity types are noted. The porosity is facies selective, but is modified by solution and cementation. Submarine, blocky calcite cement is common. Vadose pendular cement is developed beneath some exposure surfaces. Twelve lithofacies, based on texture, fauna, color, porosity, and stratigraphic position are recognized. In the lagoons, poorly connected thin beds of porosity are present, whereas the reef flank porosity is relatively thick and contiguous. Three major depositional cycles, each about 40 ft (12 m) thick, are interpreted. The first terminated with subaerial exposure and local erosional truncation. A few inches of green shale formed in the lagoon. The second cycle began with a major transgression characterized by dense dark brown laminar strom bindstone containing brachiopods, corals, and crinoids. A shallowing-upward gradation to porous massive and branching strom framestone followed. A second exposure surface, capped by discontinuous green shale, marks the termination of this cycle. The third cycle is predominantly biostromal, thickening gradually to the southwest into thin-bedded lagoonal sediments. Local well-washed rudstones suggest beach environments. Stylolites are common in the lagoonal areas, and less numerous toward the reef front. Fractures are poorly developed and have only sparse porosity. Examples of porous stylolites and fractures from the nearby Goose River reef complex are shown. End_of_Article - Last_Page 564------------

A High-Pressure Dry-Gas Miscible Displacement SchemeSimulation and Economics

Summary To develop an enhanced recovery scheme for theCardium E pool, the feasibility of waterflooding andgas injection was examined. A compositional modelwas developed to account for mass transfer andchanges in composition of this undersaturated, highly volatile oil system. High-pressure dry-gasinjection was desirable to achieve a high degree ofmiscibility. Introduction The Caroline Cardium E pool, discovered in June1974, is approximately 65 km (40 miles) southwest ofRed Deer, Alta. (Fig. 1). The discovery well was theHudson's Bay Oil and Gas (HBOG) 10–16–34–06W5, which was followed by the drilling of five additionalwells in the Bearberry Cardium A pool(T34, R06W5). The existence of a 23-km (14-mile) northwestextension of this Cardium trend was proved by thedrilling of the Pacific et al. Ricinus 10–22–36–08W5 inAug. 1975 and subsequently confirmed by the Pacificet al. Ricinus 11-28-35-07W5 in Jan. 1976. The arealextension involving T36, R08; T35, R07;and part ofT36, RO7 will be referred in this study as the areaoperated by Pacific Petroleums Ltd. The oil reservoirin these wells initially was referred to as the CardiumU pool. In Aug. 1976, an application was filed with theAlberta Energy Resources Conservation Board(ERCB)** requesting a special 130-ha (320-acre)spacing unit comprising either the northern orsouthern half of the section. This request was basedmainly on the marginal economics for developingthis thin-pay, narrow-type reservoir. It was approvedby the ERCB in an order prescribing drilling spacingunits in the Caroline area that became effectiveNov. 1, 1976. On this basis, the well allowable wasapproximately 9 m3/d (58 STB/D). By Dec. 1976, a total of 13 wells had been drilled inthe Pacific-operated area. At that time, based onpressure data and reservoir fluid analysis, Pacific pressure data and reservoir fluid analysis, Pacific filed an application requesting that the RicinusCardium E pool and the Bearberry Cardium A poolbe coalesced into the Caroline Cardium E pool.The ERCB's approval to this matter was given inFeb. 1977.1 As of June 1979, a total of 34 wells hadbeen drilled in the Pacific-operated area. To develop an optimum enhanced recovery schemefor the Caroline Cardium E pool in the Pacific-operatedarea, the feasibility of a waterflooding andhigh-pressure dry-gas miscible displacement schemeshave been examined in this study. A number ofpapers have emphasized the field application of papers have emphasized the field application of high-pressure dry-gas or vaporizing gas miscibledisplacement. It has been shown that a miscibledisplacement of oil with dry gas can be accomplishedif the oil is rich enough in the intermediatecomponents (C through C). The reservoir fluid fromthe Cardium E pool, being a highly volatile oil, appears to be amenable to undergo miscibledisplacement under high-pressure dry-gas injectionand involving multiple-contact miscibility of the gaswith the reservoir oil. JPT P. 359

Reservoir Stimulation Studies Reveal Key to Maximizing Waterflood Oil Recovery of Virginia Hills Beaverhill Lake "A" Pool

Abstract Two comprehensive simulation studies were performed on this reservoir to evaluate waterflood performance to determine the long-term production and the injection policy for the field. The results of these studies revealed that the key to maximizing economic oil recovery from the pool is to improve the vertical conformance of the waterflood. The major biohermal reservoir is found at an average depth of 5600 ft subsea and contains under-saturated crude oil in two partially overlying, non-communicating zones. Fifteen of the field's 117 wells were converted to water injectors in an irregular peripheral water/load pressure maintenance scheme. The simulation models history matched 5 years of primary performance and 10 years of waterflood performance. As it was not practical to simulate the entire field in three dimensions, a four-layer, two-phase, three-dimensional (3-D) reservoir simulation study was done on all area approximately representing the area of influence of the largest infection well. Results indicated that there was a degree of sub-layering within the layers described in this model, Flood-front saturation profiles from the history- matched three-dimensional model were employed to derive pseudo relative permeability relationships for the two-dimensional (2-D) areal model and an excellent history match of the performance of the entire pool was achieved. The study recommended a program of production logging to establish actual production/injection profiles. Results of subsequent attempts to workover wells to improve the flood profiles are discussed. Introduction It has been common practice in the oil industry for a number of yearsto conduct comprehensive reservoir engineering studies to design enhanced recovery schemes for oil reservoirs. A more recent very valuable use for in-depth reservoir studies is to optimize the performance of existing enhanced recovery schemes. Reservoir model studies on reservoirs which have considerable production history can be used to determine ways to improve performance through changes in production and injection policy, to justify remedial action to correct adverse performance und to investigate the ramifications of alternate ourses of action. Reservoir models can also be used as effective performance surveillance tools. The opportunity to improve performance of an enhanced recovery scheme is greatest when the pool is unrestricted by market demand or other arbitrary rate restrictions, because the full benefits of the changes can be realized as soon as he field responds to the change. Whenever the demand for crude oil approaches or exceeds the productive capacity of a reservoir, opportunity to optimize performance by onducting a comprehensive engineering study presents itself. To be most effective, these studies should be interdisciplinary efforts including input from reservoir petrophysical, geological and production engineering disciplines. The studies described in this paper were performed as a cooperative effort involving all of the above disciplines and the results illustrate some of the advantages gained by this cooperative approach.