Ripple acts as a real-time settlement and payment system to connect banks and payment providers. As the consensus support of the Ripple network to ensure network consistency, Ripple consensus protocol has been widely concerned in recent years. Compared with those Byzantine fault tolerant protocols, Ripple has a significant difference that the system can reach an agreement under decentralized trust model. However, Ripple has many problems both in theory and practice, which are mentioned in the previous researches. This paper presents Ripple+, an improved scheme of Ripple consensus protocol, which improves Ripple from three aspects: (1) Ripple+ employs a specific trust model and a corresponding guideline for Unique Node List selection, which makes it easy to deploy in practice to meet the safety and liveness condition; (2) the primary and view change mechanism are joined to solve the problem discussed by the previous research that Ripple may lose liveness in some extreme scenarios; (3) we remove the strong synchrony clock and timeout during consensus periods to make it suitable for weak synchrony assumption. We implemented a prototype of Ripple+ and conducted experiments to show that Ripple+ can achieve the throughput of tens of thousands of transactions per second with no more than half a minute latency, and the view change mechanism hardly incurs additional cost.

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Tapping the remaining oil with horizontal wells is routinely used in high water-cut oilfields. However, it faces serious challenges in complex fluvial reservoirs with stacked sand body, horizontal interlayers, lateral barrier and complex water flooding conditions. Moreover, the depth uncertainty of the target interval, limited number of offset wells, rapid change of thickness, thin target intervals, and variable fluid contact have also increased the risks of the horizontal well placement. In order to locate the optimal positions of the horizontal wells, get the maximum recovery, reduce the risk of water flooding, minimize the drilling time, we propose a comprehensive well planning and optimization method based on multidisciplinary innovative techniques. New techniques from geology, geophysics, and drilling engineering are assembled to efficiently perform the challenging task. Firstly, an improved interwell 3D correlation technique was proposed to characterize the single sand body. The technique can depict the vertical hierarcy of reservoir. Secondly, we propose a lateral boundary delineation technique based on seismic geometrical attribute. Combined with ant tracking algorithm, we are able to extract the 3D lateral discontinuous surfaces. Based on above technique, we can build detailed architecture model fast and optimize the positions of horizontal wells. Considering the geological uncertainty, the boundary mapping tool is used to optimize the well trajectories in real time to avoid the water flooded zone and shale zone, and to stay in the sweet zone. We applied the integrated workflow in Q oilfield in Bohai Bay basin, East China. 112 horizontal wells are drilled. The drilling results proved that boundary mapping tool can achieve smooth landing of well path and delineate the accurate geometry and thickness variation of sand body which reduces the depth uncertainty of seismic horizon explanation, and keeps the horizontal well trajectories away from oil-water contact. The production results show that 86% horizontal wells have achieved low water-cut and high oil production rate. The total production rate of Q oil field has increased by 2.5 times.

For an insurance company with a debt liability, they could make some management actions, such as reinsurance, paying dividends, and capital injection, to balance the profitability and financial bankruptcy. Our objective is to determine risk retention rate, dividend, and capital injection strategy so as to maximize the expected discounted dividends minus the discounted cost of capital injection until the time of ruin. We assume that the dividend payments and capital injection should occur with both fixed and proportional costs. We obtain explicit expressions of the optimal value functions as well as the corresponding optimal joint strategies by routine procedures in a comprehensive basic model using a new technique to solve the related equations. Our results show that whether recapitalizing is profitable or not depends on the costs of capital raising and that the firm injects capital only when the reserves are zero and recapitalizes to the optimal reserves level if the cost of external capital is low. Copyright © 2013 John Wiley & Sons, Ltd.

Guan-tao oil layer of Shu 1 Block in Liaohe oilfield is a medium deep and extra heavy oil reservoir, which has high porosity and high perm with edge water. In 2001, cyclic steam stimulation was applied with square well pattern and well-space 70m. After 9–10 cycles the stimulation development effect deteriorated and the degree of reserve recovery was only about 15%. To seek development method of extra heavy oil reservoir and improve the entirety recovery ratio of this block, after the feasibility research on SAGD technology in Guan-tao oil layer was finished, horizontal wells were infilled between vertical wells and 4 SAGD pilot test well groups combining vertical wells with horizontal wells were conducted Three cycles of cyclic steam stimulation to preheat the formation and decrease pressure were proceeded and the 4 well groups had produced for 1 year after converted to SAGD. Daily oil production capacity of single horizontal well increased from the initial 20–40t/d to 70–80 t/d after the multiple adjustment of the injection-production parameters. Preferable period effect was accomplished and the test provides good guide for same medium deep and extra heavy oil reservoir to change their development methods. Survey of the test block Block Du 84 locates on the middle of Huan-Shu structural belt of the western slope in the West Depression of Liaohe Basin. The Guan-tao oil-layer of Block Du 84 , shallowly buried , is a thick blocklike extra heavy oil reservoir with high porosity , high perm to extra high perm and , underscreen water??basal ground water and edge water. SAGD pilot test area lies in the north of Block Du 84(Figure 1). It is a monoclinal structure acclive to south-east and the structural dip is about 2–3 degree. No fault is found and its sands distribute continuously. The oil layer depth is 524–668m and the average net pay thickness is 91.7m, no basal ground water is found. The reservoir lithology was chiefly middle-coarse sandstone and inequigranular sandstone, average median grain diameter is 0.42mm. Reservoir quality is good , the average porosity is 36.3% and average perm is 5.54µm2, average oil density under 20°C is 1.007 g/cm3, the degassed oil viscosity under 50°C is 23.191×104 mPa·s, resin and asphaltine is 52.9%, solidifying point is 27°C, paraffin content is 2.44%, the oil-bearing area is 0.15km2, geologic reserve is 249×104t, and the initial formation pressure is 6.02MPa. Progress of the test Based on the development condition and well pattern of extra heavy oil reservoir in Block Shu 1, and associating with the result of numerical simulation, SAGD pilot testing program concerning vertical and horizontal wells was drawn up. Four infilled horizontal wells named Guan-ping 10-- Guan-ping 13 were selected to form test well groups with around 34 vertical wells. The injector-producer distance is 35m, horizontal well spacing is 70m, horizontal segment size is 350–400m. What differs from in Canada is that the producing horizontal wells were infilled between the used vertical wells and below the vertical wells, 5m distance from the perforated intervals of vertical wells. The test from December of 2003 to June of 2006 was devided into two periods: steam huff and puff period to preheat the formation, SAGD producing period. Cyclic steam stimulation period to preheat the formation The pilot test block is a medium deep reservoir and the initial formation pressure is comparatively high. CSS has been applied in vertical wells for average 7.2 cycles before participate in preheat together and the recovery percentage was 12.7%. However, the formation pressure between wells didn't fall down too much. Because the horizontal wells are allocated between vertical wells where thermal connect doesn't exist and operation should be under low pressure condition during SAGD period, vertical wells and horizontal wells operate together during cyclic steam stimulation period to preheat the formation to achieve the condition help to convert to SAGD.