The multilateral well technology was used for the first time in Albian Third Sand reservoir of the super-giant Greater Burgan Field of Kuwait. The reservoir is on production for more than 60 years with conventional development techniques. The multilateral drilling technology was adopted particularly for exploiting the heterogeneous and complex units within Third Sand Upper member of Burgan Formation. The Third Sand Upper (3SU) unit came up as the right candidate because of its low thickness, relatively poor reservoir quality and inconsistent occurrence rendered it difficult to exploit by conventional wells. On the contrary the more prolific Third Sand Middle unit (3SM), was not considered for multilateral drilling because of its massiveness and hydrodynamic connectivity. Nodal Analysis results suggested comingled production from 3SU and 3SM as not suitable, because of high pressure differential and permeability contrast. The 3SU was deposited in a broad transgressive set up. As expected in such transgressive units, the sands are thin, heterogeneous and discrete in nature. Paleogeography and sand thickness maps helped in understanding the geometry of the sand bodies for suitable placement of the laterals. A pre-drill model was built based on the logs of the nearby wells to predict the facies in the laterals. Two stacked bilateral wells were drilled to drain different layers in two separate locations. Multilateral TAML-4 level was selected for adequate junction stability and options for possible re-entry. The lateral length varied from 650 to 1663 ft depending on the spatial distribution of the sand bodies. Effective geosteering through 5 to 10 ft thick sand layers in these wells encountered 0.5 to 1.5 Darcy reservoirs. These thin, discontinuous layers produced about 3000 to 5000 BOPD on production testing, thereby increasing the expected productivity six fold compared to vertical wells. The success obtained in producing from these thin, heterogeneous and otherwise under exploited reservoirs will open up new fundamentally different and improved development opportunities Introduction The Greater Burgan Field located in Southeast of Kuwait (Figure 1) is a north-south trending anticline, and covers an area of about 450 square mile. It consists of three three major fields, Burgan, Magwa and Ahamdi with hydrocarbon contained in three major reservoirs namely Wara, Burgan and Maudud (Lower Cretaceous) and two minor Jurassic carbonate reservoirs Minagish and Marrat (Figure 2). The Burgan field was discovered in 1938 and went on production in 1946. The first wells drilled in Magwa and Ahmadi were in 1951 and 1952 respectively. The Greater Burgan Field is the world's largest siliciclastic oil field which is on production for more than 60 years. In Greater Burgan Field, the principal producers are the Burgan and Wara reservoirs. Its primary producer is the Third sand middle 3SM unit which contributes a major part of the total field production.
In the MG field located in the South east of the State of Kuwait, the 3rd Sand Upper deposits are found at depths of nearly 4000 ft and feature a more complex geological structure when compared to the greater Burgan deposits. Furthermore, the 3rd Sand upper deposits feature multiple successive layers with different lithology with low reservoir pressure (1500 psi) & temperature (135F). To achieve economic well production from such formation, conventional stimulation techniques have been applied & showed minor none economical production. Accordingly, the 3rd Sand upper reservoir are kept undeveloped looking for solutions. Conventional Hydraulic fracturing Techniques are well known as a reliable method for increasing well productivity from the tight & heterogeneous reservoirs. However, it will not be applicable in the 3rd Sand upper reservoirs mainly due to; 1) the operational challenge of placing successfully huge fracturing treatment to achieve the desired longest possible fracture geometry, 2) the difficulties of flowing back the huge quantities of the guar based fracturing fluids in such low pressure-low temperature reservoir. Failure place sufficiently massive treatment or flow back of fracturing fluids will reduce the effective fracture half length & compromise the full production potential. Recently, the Channel-Fracturing technique has been successfully applied in 5 wells in MG field with same reservoir challenges explained above. The Channel-Fracturing techniques changed the concept of the hydraulic fracturing & overcome its disadvantages. Whereas the conventional fracturing treatments rely mainly on the placing as huge as possible proppant mass & its associated carrying fluids, the Channel-Fracturing technique concept relies on creating open-flow channels utilizing less proppant quantities. Pulses with proppant are separated by pulses of clean fluid, which creates proppant clusters inside the fracture &holding the walls of the fracture open. The channel-Fracturing techniques will ensure longer effective fracture half-length and, consequently, production rates. In addition, to the reduced required proppant quantities which reduced the placement risk & material cost, one of those wells was customized massive Channel-Fracturing treatment for the first candidate well in the field to place 350KLB of proppant equivalent to 800 KLB of a conventional treatment to achieve +/- 500ft of effective fracture half-length laterally in the 3 Sand upper reservoir. The Treatments has been executed successfully throughout the whole campaign as designed without any pre mature sand screen out or completion failure due to pressure build up. Then the well opened to flow & showed a natural flow of 200% compared to the estimated gain. The treatment bottom hole pressures analysis clearly identified a signature of a successful treatment. The successful results in this campaign managed to unlock the reserve and allow development of the 3rd Sand upper reservoir in the SEK fields.
Objectives/Scope The acquisition of mud gas data for well control and gathering of geological information is a common practice in oil and gas drilling. However, these data are scarcely used for reservoir evaluation as they are presumably considered as unreliable and non-representative of the formation content. Recent development in gas extraction from drilling mud and analyzing equipment has greatly improved the data quality. Combined with proper analysis and interpretation, these new datasets give valuable information in real-time lithological changes, hydrocarbons content, water contacts and vertical changes in fluid over a pay interval. Methods, Procedures, Process Post completion, Mud logging data have been compared with PVT results and they have shown excellent correlation on the C1-C5 composition, confirming the consistency between gas readings and reservoir fluid composition. Having such information in real time has given the oil company the opportunity to optimize its operations regarding formation evaluation, e.g downhole sampling, wireline logging or testing programs. Formation fluid is usually obtained during well tests, either by running downhole tools into the well or by collecting the fluid at surface. Therefore, its composition remains unknown until the arrival of the PVT well test results. This case intends to use mud gas information collected while drilling to predict information about the reservoir fluid composition in near real time. To achieve this goal we compared mud gas data collected while drilling with reservoir fluid compositional results. Pressure volume temperature (PVT) analysis is the process of determining the fluid behaviors and properties of oil and gas samples from existing wells. Results, Observations, Conclusions The reason any oil and gas company decides to drill a well is to turn the project into an oil-producing asset. But the value of the oil extracted from a single well is not the same as the value of the oil produced from another. The makeup of the oil, which can be determined from the compositional analysis, is an important piece of the equation that determines how profitable the play will be. The compositional analysis will determine just how much of each type of petroleum product can be produced from a single barrel of oil from that wells. Novel/Additive information Formation samples were obtained from offset wells in the Marrat Formation. These datasets gave valuable indications on fluid properties and phase behavior in the reservoir and provided strong base for reservoir engineering analysis, simulation and surface facilities design. The comparison of the gas data to PVT results gives a good match for reservoir fluid finger print, early acquisition of this data will help for decision enhancement for field development.
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