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Background To describe the outcomes of patients with retinitis pigmentosa (RP) who received the Argus II Retinal Prosthesis System. Methods This retrospective, interventional case series evaluated 10 consecutive patients who received the Argus II retinal implant and underwent visual function tests with the system on and system off. The main outcome measures were safety (the number, seriousness, and relatedness of adverse events), and visual function measured by computer-based objective tests, including square localization (SL) and direction of motion (DOM). Secondary measures included functional vision performance, including orientation and mobility (O&M) tasks. Results There were no intraoperative complications and all prostheses remained implanted at the end of follow up. The mean patient age was 41.3 years; mean duration of the implant in vivo was 2.1 years. One patient had a suture exposure over the coil suture tab and over the inferior case suture tab at 2 years postoperatively, which was managed successfully. One patient developed mild vitreous hemorrhage that resolved spontaneously. One patient developed high intraocular pressure postoperatively due to a tight scleral band (SB) that was managed successfully. Patients performed significantly better with the Argus II system on than off on all tasks. Conclusion Patients who received the Argus II had a safety profile out to 4 years post-implantation that was markedly better than that observed in the pre-approval phase of the Argus II. In this population of RP patients, the Argus II retinal prosthesis provided useful visual function over several years that likely translates into improved quality of life. Trial Registration: clinicaltrials.gov identifier, NCT00407602.

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Initially, it was believed that a horizontal well should be drilled as long as possible. This was motivated by the advancements in horizontal well drilling, which allows horizontal wells to be drilled several thousands of feet long. However, field experience and flow meter surveys in long horizontal drain-holes revealed that the frictional pressure loss in the wellbore is an important factor limiting the effective length of long horizontal wells and consequently hindering the full use of the entire length of the horizontal wells. Flow meter surveys revealed that the productivity of long horizontal wells is not proportional to well length because the increase in the length of horizontal section results in significant frictional losses in the wellbore. The frictional pressure losses may be comparable with the drawdown at the producing end of the well rendering a portion of the horizontal drain-hole unproductive.This paper presents a new approach to maximize the use of the full length of long horizontal drain-holes by producing these long horizontal wells from both ends (heel and toe) and/or intersecting the second half of the horizontal well at an optimized location. This approach is supported by development of a rigorous semi-analytical model for the transient pressure analysis and well productivity evaluation for the horizontal well producing from both wings at the desired rates from both wings. The model incorporates the impact of wellbore hydraulics into the solution and used to calculate the flux distribution and pressure profile along the horizontal section. The developed model can also be used to evaluate the impact of reservoir parameters on the horizontal well performance. Furthermore, the model can be used as an optimization tool to optimize the production of long horizontal well by producing the well at the desired flow rates from both wings. Also presented, are some results showing the impact of wellbore hydraulics on the flux profile along the horizontal wells. These results show that the flux profile is a function of combination of reservoir flow characteristics and well conductivity. Wellbore hydraulics changes the flux distribution (flow ingress profile) along the wellbore and, thus, results in additional pressure drop in the well. The proposed method is found to be superior to the conventional horizontal well in terms of productivity and flux profile.

The need for oilfield operators to verify that wells are being produced at their optimum capacity and in a cost effective manner is always a priority. The need for total well management to reduce operating costs, increase oil production and increase net income from wells requires an integrated analysis of the pumping system including the performance and interaction of all the elements: the reservoir, wellbore completion, and the downhole pump. Well Completion is typically designed to assure certain oil flow rate whilst producing manageable volume of water to ensure good reservoir sweep efficiency and management. Completion design is always based on collected production data of forecasted reservoir performance of changing pressure and water cuts. As oil fields mature with subsequent increase of water cut and decrease in pressure, artificial lifting is becoming a vital mechanism for maintaining the production plateau of the field. With the emergence of the inflow control devices (both passive and active), the thrust for artificial lifting is delayed due to the delay of onset of water production or reduction of water volume produced. Very recently, the industry has looked into combining artificial lifting with controllable inflow devices. This paper addresses the different optimization scenarios of well completion in high productivity wells considering the life cycle of artificial lift systems (mainly ESP's) and different flow control mechanism. The paper highlights cases of applications extreme values of water gravities. In addition, underlines the economic viability of artificial lifting due to maintaining production and reducing cost in some applications.