Overview: Artificial Lift (May 2005)

Collective Wisdom and Multidisciplinary Tumor Boards

A Comparison of Assertive Community Treatment and Intensive Case Management for Patients in Rural Areas

VICO Indonesia has operated the Sanga-Sanga PSC in East Kalimantan, Indonesia, since 1968. More than 750 development wells have been drilled to date in the complex Mahakam Delta in East Kalimantan. The mature reservoirs are predominantly gas, extremely depleted and have an average recovery factor of about 70%. To optimize the development cost VICO changed the completion from multi string and multi packers to monobore in 1997 and furthermore to dual monobore in 2005. VICO has also focus to optimize oil production and recovery. The current oil recovery factor is relatively modest and needing further detail study and optimization. A multi-disciplinary team was performed to further evaluate oil potential in all VICO fields including review of historical performance, geology and development opportunities. These reservoirs were also evaluated using material balance to understand the initial volumes in place, the drive mechanism and the opportunity to maximize production and oil recovery through the existing wells. One of the challenges in maximizing oil recovery is artificial lift system in monobore completion. VICO has evaluated and selected gas lift as optimum artificial lift method. There are two possibilities to gas lift oil wells (1) using a side pocket mandrel in the conventional dual string completion and (2) inject gas lift through coil tubing in the monobore completion. The paper describes innovative gas lift system in monobore completion where gas lift mandrels were not pre-installed. This technique has been implemented, by running 1.5" coil tubing into a well through a special tubing hanger attached to the top of the Christmas tree. This technique allows gas lift to an oil reservoir in monobore well completion without requiring rig for recompletion. This application is known as "Permanent Coil Tubing Gas Lift" or PCTGL. This technique has been implemented in "MUT-X" well that was not capable to flow naturally, and then PCTGL was installed to resume oil production. The well was flowing 600 BOPD initially and now is continue flowing at 350 BOPD. In summary, PCTGL is a proven favorable and simple method for artificial lift application in monobore completion to maximize oil production and recovery. Furthermore, this technique has helped VICO in synergizing gas and oil development to maximize value of the assets.

Multidisciplinary team (MDT) approach has been shown to reduce diabetic foot ulcerations (DFUs) and lower extremity amputations (LEAs), but there is heterogeneity between team members and interventions. Podiatrists have been suggested as “gatekeepers” for the prevention and management of DFUs. The purpose of our study is to review the effect of podiatric interventions in MDTs on DFUs and LEAs. We conducted a systematic review of available literature. Data’s heterogeneity about DFU outcomes made it impossible for us to include it in a meta-analysis, but we identified 12 studies fulfilling inclusion criteria that allowed for them to be included for LEA outcomes. With the exception of one study, all reported favourable outcomes for MDTs that include podiatry. We found statistical significance in favour of an MDT approach including podiatrists for our primary outcome (total LEAs (RR: 0.69, 95% CI 0.54–0.89, I2 = 64%, P = 0.002)) and major LEAs (RR: 0.45, 95% CI 0.23–0.90, I2 = 67%, P < 0.02). Our systematic review, with a standard search strategy, is the first to specifically address the relevant role of podiatrists and their interventions in an MDT approach for DFU management. Our observations support the literature that MDTs including podiatrists have a positive effect on patient outcomes but there is insufficient evidence that MDTs with podiatry management can reduce the risk of LEAs. Our study highlights the necessity for intervention descriptions and role definition in team approach in daily practice and in published literature.

Modern simulation capabilities were recently applied to the K2 Field to help define a risk-reducing phased development. This integrated study relied heavily on new advances to handle complex fluid behavior, derive a history match, resolve future behavior of sub-sea wells, and seamlessly review economic metrics. Simulations used tightly-coupled surface and subsurface calculations to capture and stabilize the interaction of surface facilities with the reservoir. This robust and rigorous approach improves upon previously reported techniques in which subsurface flow calculations are only loosely coupled to the surface network. Fluid characterization involved a single equation of state with multiple distributed component sets in reservoirs and compositional mixing within the surface network. Super-critical initialization was used to represent an unusual compositional transition from a highly undersaturated oil rim to an undersaturated gas cap. History match parameters included reservoir, facilities, and well properties. A host of development options involving artificial lift (AL), additional wells, miscible gas injection, and water injection was evaluated for economic value through an optimization-under-uncertainty approach. This assessment guided a multi-disciplinary project team to detail a short set of developments for highest consideration in a common situation where the complex interactions among the reservoir, wells, outflow network, and facilities, makes an intuitive solution inaccessible. Although the four geologic models used were considered adequately diverse for the study, further value lies in broadening the geological uncertainty and hence the range of possible outcomes. While a relatively new application in deepwater fields, AL is recognized as a technology to extend producing life for mature fields and enable production from challenging plays such as the Gulf of Mexico lower Tertiary. Few case studies addressing such situations are available. The presented workflow may be repeated on assets with significant outflow performance drivers – assets that would benefit from modeling and resolution of complex surface/subsurface interactions.

The time taken to safely optimise a reservoir produced by artificial lift can be measured in weeks or months. Typically the well by well process is as follows: Well testingAmalgamation of the well test data with down hole gauge and ESP controller dataAnalysis of the data to find the existing operation conditionsAnalysis of the ESP pump curve operating point and optimisation limitationsSensitivity studies in software to assess the optimum frequency and WHPNotification for the field operations to action the changesFurther well tests to verify the new production data.Analysis of the data to ensure the ESP and well are running optimally and safely at the new set points New technology enables this process to be performed in real time across the entire reservoir or field, significantly shortening the time to increased production and enabling real time reservoir management. Each artificially lifted well in the reservoir was equipped with an intelligent data processing device programmed with a real time model of the well. The processors were linked to a central access point where the operation of field could be remotely viewed in real time. Each well’s processor was provided with a target bottom hole flowing pressure to enable the optimum production of the reservoir. The real time system automatically compared the desired target drawdown values with the capability of the pumping system installed in each well, and automatically suggested the optimum operating frequency and well head pressure to achieve the target. Where the lift system was not capable of producing to the target bottom hole pressure, a larger pump was automatically recommended. As production conditions change the system adapted its recommended operating points to compensate and maintain target production. This paper discusses three case studies where real time optimisation and diagnosis lead to improved production from the reservoir.

Nowadays gas-lift is still a very expressive artificial lift method, for instance considering the whole Brazilian oil production profiles, gas lifted wells are responsible for 30% of monthly production. Due this huge importance, the injection efficiency should be ensured to avoid lid gas losses and maximize the production. Then, this study had as objective to develop a Gas Lift Optimization workflow and define the optimum lift rates to increase the reservoir recovery and improve gas usability due to platform constraints of a Brazilian deep-water field. That workflow comprises a reservoir and flow assurance simulators, achieving more accurate responses compared to regular workflows. Taking advantages of the proposed method, multidisciplinary teams could work together which increases the representativeness of such studies providing important outcomes for decision makers. At this study, due to a gas-lift optimization was observed an increase of 0.5% at cumulative production with a huge gas-lift reduction of around 40%, resulting in a better financial balance of the project, saving a considerable amount of lift-gas. The methodology adopted to optimize the injected gas lift rate and consequently increase/maintain cumulative oil production proved adequate for application in oil fields that are highly dependent on artificial lift methods. Therefore, exploration and production projects can be financial healthier.

A marginal field in the East Malaya Basin contains bypassed reserves in shallow, high-angle reservoirs where conventional drilling is uneconomic. Coiled-tubing drilling (CTD) was identified as a cost-effective solution, but remote unmanned platforms and vessel dependency increase costs and risks. A phased approach separating preparatory operations from drilling proved critical in derisking execution, optimizing vessel utilization, and reducing nonproductive time, while maintaining safety and operational efficiency. Candidate wells were screened using a multidisciplinary approach considering reservoir quality, well integrity, accessibility, artificial lift, and intervention feasibility. The preparatory (pre-CTD) phase was executed with real-time electrical coiled tubing (RTECT), minimizing surface footprint and enabling wireline functionality through coiled tubing (CT). Key steps included isolating the original reservoir, installing and logging annular cement barriers, and setting the whipstock for sidetrack initiation. Feasibility studies assessed vessel limits, platform readiness, and CT compatibility, ensuring readiness and regulatory compliance prior to the main CTD campaign. The pre-CTD campaign validated CTD as a viable, lower-cost alternative to conventional drilling in this marginal, infrastructure-limited field. Decoupling preparatory operations reduced uncertainty, streamlined logistics, and improved safety, while RTECT enabled wireline-dependent tasks such as cement evaluation and whipstock orientation without additional equipment or personnel. This reduced surface complexity, minimized vessel time, and lowered health, safety, and environmental (HSE) exposure, achieving a 13% cost saving versus conventional approaches. The smaller operational footprint was especially advantageous for remote, unmanned platforms with limited deck space. Delivery under an integrated contract model further enhanced coordination, reduced interface risks, and accelerated decision-making. Collectively, these outcomes demonstrate the technical and economic feasibility of phased CTD deployment for late-life offshore assets, providing a repeatable model for accessing bypassed reserves in similar environments. Separating the pre-CTD phase from the drilling campaign provides a structured, lower-risk path to evaluate well viability before full execution. This phased approach enhances scheduling flexibility, mitigates uncertainties, and avoids unnecessary rig or vessel exposure. Demonstrated with RTECT in a marginal offshore field, it establishes a practical blueprint for economically unlocking bypassed reserves under vessel and platform constraints.

Field Development Plan (FDP) of the North Kuwait Jurassic Gas (NKJG) asset in Kuwait served as the basis of the yearly asset action plan, future development wells, development options and production forecast. Due to nearly fourfold increase in gas offtake and the increased number of wells, new production challenges, ongoing appraisal results from the deeper contact area, it was decided to update FDP based on the new data/challenges and using the new technologies. In a modified version of Shell's standard Opportunity Realization Process (ORP), a phased approach for developing fields is applied. The NKJG asset approach to this standard ORP process is different in two ways: – The pace of development/activities is very high, driven by gas demand– Concurrent appraisal, development planning, execution activities, and operation of the fields The FDP work was carried out by an integrated, multi-disciplinary team consisting of KOC, SLB and Shell staff. A number of new technologies have been applied to solve current production issues. The results for this work comprise of: – Base case depletion drive development plans with the updated well count for each reservoir.– Production forecast for all potential, current and future development wells (different well types based on reservoir conditions/properties) was delivered.– Development decisions like compression, artificial lift (AL), velocity string and well types (multistage frac, multi-lateral) are also addressed in this FDP update.– Gas recovery factor has increased as the very low pressure (VLP) compression was introduced in this work.– Additional gains because of better drainage, longer production period and VLP. This work presents some of the new technologies which enhance oil and gas production and solve development challenges in complex tight carbonate, highly fractured HP/HT reservoirs, sour near critical fluids, in a congested surface area fields. Examples from these technologies are multilateral wells and different types of wells, CO2 energized and multistage frac stimulation, AL, and VLP. Integrated work has been done using dual permeability modelling system to test impact of different technologies on production profile.

With the prevalence of head and neck squamous cell carcinoma (HNSCC) nearly twice as high in veterans (6%) than general populations (3%), the noted problems of long waits and access to care in United States Veterans Affairs (VA) hospitals across the country are pressing. We examined primary outcome measures of timeliness and access to care for our patients with HNSCC assessing a multidisciplinary team approach at our VA hospital. Retrospective chart review. Our patients newly diagnosed with HNSCC were identified from two 24-month periods: diagnosis before (group 1, 2005-2006) and after (group 2, 2008-2009) implementing our multidisciplinary team in 2007. No significant differences in age (P = .13) or disease stage (P = .18) occurred between groups. Primary and secondary outcomes (i.e., treatment modality, imaging, completion of treatment, survival) were compared. Timeliness to care improved for all measures. Improvement was significant for times from consult placed to seen in clinic (27.5-16.5 days; P < 0.0001) and from positive biopsy reported to date of initiating definitive treatment (35-27 days; P = 0.04). Pretreatment consults to various services represented by the multidisciplinary team increased from one to four (P < 0.0001). Two-year mortality was approximately the same between group 1 (33%) and group 2 (36%) (P = 0.035). Five-year mortality was slightly better in group 2 (50%) versus group 1 (61%), although not statistically significant. Our veteran population with HNSCC had improved timeliness and access to care with our multidisciplinary approach. 4. Laryngoscope, 126:627-631, 2016.

IntroductionThere are several well-known barriers to conducting research in hospices. Hospices may lack experience of research and have less developed governance procedures. The vulnerability of patients and the sensitivity of...

The standard water institutions, governance and infrastructure reform and policy prescription package of the 1990s and early 2000s, i.e., restructuring, private-public partnerships (PPP), establishment of an independent regulator, have not yielded positive results for South Africa. These water institutions and governance challenges are resulting in inadequate investments, and millions in South Africa not having access to basic water and sanitation services. The framework for water sector infrastructure funding models was designed to meet the challenges presented by the current and growing imbalances that exist between the supply of and demand for water in South Africa. The research results identified 7 overarching governance models for the funding, financing and development of water infrastructure projects in South Africa, i.e. Model 1: direct fiscal (NRF) funding, Model 2: ring-fenced special purpose vehicle (SPV), Model 3: SPV housing dedicated water infrastructure cash-flows, Model 4: stand-alone water institution with strong balance sheet, Model 5: public-private partnership (PPP) with equity, Model 6: private concession, and Model 7: private development. Various institutional options for consideration for the future management and development of water infrastructure were investigated and considered. The emerging model is considered to be a hybrid model consolidating the national water resources and regional bulk infrastructure functions and capabilities, with regional bulk infrastructure primarily being a water board (water services provider) function.

To define and validate the role of the community nurse in a multidisciplinary team caring for clients with chronic and complex needs. A key factor in optimising care for clients with chronic and complex conditions in the community is the use of multidisciplinary teams. A team approach is more effective as it enables better integration of services. The role of the community nurse in the multidisciplinary team has as yet not been delineated. A modified Delphi technique was used in this study. A group of 17 volunteer registered nurses who were experienced in the care of clients with chronic conditions and complex care needs in the community formed a panel of experts. Experts were emailed a series of three questionnaires. Main findings show that the role of the community nurse in a multidisciplinary team for clients with chronic conditions has six main domains - advocate, supporter, coordinator, educator, team member and assessor. A consensus on the role of the community nurse in the multidisciplinary team is described. The six key role domains reaffirm the generic role of the nurse and the validation of the role clarifies and reinforces the centrality of the community nurse in the team. Further refinement of the community nurse role is indicated to increase comprehensiveness of role descriptors particularly for the role domain, advocate. Community nurses working in multidisciplinary teams caring for clients with chronic conditions can define their role as a team member. The working relationship of the community nurse with other health professionals in the multidisciplinary team as a key approach to more integrated care for clients and carers enables the use of this approach to be better understood by all team members. With this increased understanding, community nurses are in a position to build stronger and more effective care teams.

A multidisciplinary team approach to patient care is a concept that is widely used today, mainly in inpatient settings, although it is not always well understood. This is not a new concept as patient care is by definition multidisciplinary, with patients generally requiring evaluation and treatment from more than one professional during a stay in hospital. The key words here are ‘team approach’. This requires a group of professionals and the patient to work together with agreed aims. There needs to be active and equal participation by all team members, including the patient, in setting goals, applying treatments and evaluating responses. Success of treatment means different things to different people, and clinicians and patients often use different criteria in judging a treatment's efficacy. Therefore, each team member needs to develop good listening and communications skills. A multidisciplinary team approach is not about everyone just ‘doing their bit’, but also doing it at the appropriate time and not in isolation.

In the United States, the incidence rate of new or recurrent stroke is approximately 795 000 per year, and stroke prevalence for individuals over the age of 20 years is estimated at 6.5 million.1 Mortality rates in the first 30 days after stroke have decreased because of advances in emergency medicine and acute stroke care. In addition, there is strong evidence that organized postacute, inpatient stroke care delivered within the first 4 weeks by an interdisciplinary healthcare team results in an absolute reduction in the number of deaths.2,3 Despite these positive achievements, stroke continues to represent the leading cause of long-term disability in Americans: An estimated 50 million stroke survivors worldwide currently cope with significant physical, cognitive, and emotional deficits, and 25% to 74% of these survivors require some assistance or are fully dependent on caregivers for activities of daily living (ADLs).4,5 Notwithstanding the substantial progress in acute stroke care over the past 15 years, the focus of stroke medical advances and healthcare resources has been on acute and subacute recovery phases, which has resulted in substantial health disparities in later phases of stroke care. Additionally, healthcare providers (HCPs) are often unaware of not only patients’ potential for improvement during more chronic recovery phases but also common issues that stroke survivors and their caregivers experience. Furthermore, even with evidence that documents neuroplasticity potential regardless of age and time after stroke,6 the mean lifetime cost of ischemic stroke (which accounts for 87% of all strokes) in the United States is an estimated $140 000 (for inpatient, rehabilitation, and follow-up costs), with 70% of first-year stroke costs attributed to acute inpatient hospital care1; therefore, fewer financial resources appear to be dedicated to providing optimal care during the later phases of stroke recovery. Because there remains a …