This paper describes the field application of a novel wireline conveyed cased-hole formation dynamics tester designed to drill a hole in casing, measure formation pressure and permeability, identify and retrieve downhole fluid samples and seal the hole with a bi-directional plug. Until recently the only way of obtaining such information in cased hole was either by performing aDST or using a modified open-hole tester (needing explosives and squeeze cementing). The Sembakung field, N.E. Kalimantan was discovered in 1975 and has produced over 37 MMBO. The main producing interval is the Upper Middle Miocene Tabul formation. Over 35 separate sands have been identified in this highly stratified reservoir and producing wells have multiple commingled zones. The reservoir and crude quality is good (f=15–30%, K=200–2000 mD, 37 API, low-sulphur low-wax). Equatorial Energy acquired an 80% stake in the TAC in 1998 and commenced an aggressive program of infill drilling, as well as acquired a 3-D seismic surveyin 2001. 3D seismic uncovered the presence of a significant southward structural extension with additional exploration potential. It also revealed the existence of new untapped reservoirs and structural compartmentalization within the field. Declining pressures and signs of inter-well communication indicated the urgency of field pressure maintenance. Drillstem testing was not feasible as a large number of potential zones needed to be tested. This novel tool proved useful in managing the challenge. The tool was run successfully in 7 wells where it drilled and tested 71 holes in casing and recovered fluid samples. Formation pressures were measured, permeabilities estimated and fluids identified using downhole pump out with optical spectroscopy. The performance conclusively demonstrated the applicability and cost-effectiveness of this novel technique in revival of this oilfield. Sembakung Field The Sembakung field is located in N. E. Kalimantan state of Indonesia and lies in the oil and gas bearing Tarakan basin of onshore North-East Borneo. The location map is shown in Figure 1. Stratigraphically, the Tarakan basin consists of a prograding deltaic sequence from upper Miocene through Pliocenetime. Figure 2 shows the typical stratigraphy of the Tarakan basin. Fields in the basin produce from stacked deltaic sands of Miocene and Pliocene age instructurally controlled traps. Ref. 1 gives a good account of the tectonic history and hydrocarbon geology of the Tarakan basin. The Sembakung feature is a northwest to southeast oriented anticline with abroad northern end and a steeper western flank. The west and east sides of the anticline are bounded by high angle thrust faults forming a reverse flower structure (Ref. 2). Figure 3 is a northwest to southeast seismic cross-section across the Sembakung field, which clearly brings out these features. The main productive interval in the field is the Upper Middle Miocene Tabul formation consisting of thinly interbedded sands and shales. The field is shallow, with the sands occurring over the interval –1600 to –3500 ft subsea. About 35 different sand groups have been identified varying in thickness from a few feet up to 30 feet. A majority of the production comes from the 24 AB to 28sand interval. Figure 4 is a structure map of zone 24 CD, which is one of the main producing sands. The field has been producing since 1977 with a maximum initial production of11,700 BOPD and cumulative production of over 37 MMBO. The field had since then been left on natural decline with a low production rate. Equatorial Energy acquired the field in 1998, carried out a 3-D seismic survey and redeveloped it with closer infill drilling. A significant southward structural extension was found and previously untapped reservoirs identified. Current oil production from the field stands in excess of 7000 BOPD.

Essentials Efficacy and safety data on recombinant hirudin gels for the treatment of hematomas is limited.We assessed the clinical efficacy of a topical r‐hirudin gel in 199 patients with hematomas.Treated patients exhibited significant reductions in hematoma size and flare within 16 days.r‐hirudin gel treatment induces a complete resolution of hematomas and associated edema in 98%, and 99% of patients, respectively. BackgroundHirudin is the most potent direct thrombin inhibitor, and recombinant forms are routinely used in anticoagulation therapy. Recombinant hirudin gels are commercially available for the treatment of hematomas and associated symptoms.ObjectivesTo assess the efficacy and safety of a topically administered recombinant hirudin gel in patients with hematomas.Patients/MethodsThis double‐blind, placebo‐controlled, phase IV investigation recruited patients presenting with at least one hematoma. Subjects were randomly assigned (1:1) recombinant hirudin gel (1120 IU/100 g) or a placebo, administered 2‐3 times daily for 16 days. Changes in hematoma size, flare, and the proportion of patients achieving complete resolution of hematomas and associated edemas were investigated.ResultsBy study end, a greater proportion of subjects in the treatment group achieved a complete resolution of hematomas versus placebo (98.0% vs 71.9%; P  < .001) and edemas (99% vs 50%; P  < .001). Patients in the recombinant hirudin group exhibited a marginally larger, yet significant, reduction in mean hematoma size versus placebo (99.9% vs 96.6%; P  < .001) and flare (93.6% vs 78.6%; P  < .001). Median time to hematoma resolution for the recombinant hirudin and placebo administered cohorts was 8 and 16 days, respectively (P  < .001). No adverse events were reported for the recombinant hirudin cohort.ConclusionsTopical recombinant hirudin is an effective, safe, and well tolerated intervention for the symptomatic treatment of hematomas. This trial was registered at http://www.clinicaltrials.gov as NCT01960569.

The Eastern Mediterranean hosts some of the largest and most prolific gas reservoirs in the region. These reservoirs have been deposited as slope submarine channels and basin floor turbidite sand sheets. The quantity and quality of production is often controlled by the architectural elements encountered. Slumped and deformed facies could hinder production in submarine channels of the slope setting, which are limited in lateral extent. Although laterally continuous and parallel thinly bedded turbidite sheets of the basin floor offer great lateral extent, they often exhibit poor vertical connectivity and low apparent resistivity due to thinly bedded sand/shale sequences. An exploratory well was drilled in the Offshore Nile Delta targeting slope and basin floor deposits. Although seismic attribute interpretation provided a general outline of the area, there remained the uncertainty of whether the depositional setting encountered by the penetrated succession belonged to slope channels or basin floor setting. The value added through borehole image integration provided information regarding some unanswered questions: 1) Are sidewall cores representative of surrounding lithology? 2) Do sedimentary features support a slope or basin floor model? 3) Are there natural fractures to enhance porosity? 4) What is the reason for low porosity in the sands? 5) Are there additional thin beds between channel elements? To answer all these questions, detailed structural, sedimentological and sand count analyses were performed on the micro-resistivity image, logged over a 500 m succession. Interpreted electro-facies differentiated the internal architectural elements from structural events within the penetrated succession. Slumping and water escape structures supported a slope channel setting while dip patterns directly above channel fills were interpreted as levee complexes of nearby channels. Sand counting of the image resistivity arrays included all possible thin beds that could contribute to pay while excluding all deformed facies that would hinder production performance.