This paper presents the analyses of well tests and production logging carried out on three multi-fractured horizontal wells in the Babbage tight gas field, UK Southern North Sea. The actual performance observed in these wells was compared to the forecasts made based on open-hole well data and the data gathered during hydraulic fracturing operations. Some of the drawbacks in analysing well test data are discussed along with the uncertainties in modelling hydraulic fractures. Horizontal wells with multiple hydraulic fractures are used to increase productivity and recovery in tight reservoirs. Understanding and predicting fracture performance is essential to the field commerciality considering the associated high development costs, especially in the North Sea.The results of this study indicate that based on several pressure transient analyses, the clean-up time can be up to several months, which was observed in the form of gradual skin reduction over time. The PLT data also confirmed that there is cross flow during the shut in periods, usually flowing from the outer fractures into the inner fractures. This was believed to have an impact on the interpretation of the build-ups. Moreover it was shown that during build-up tests of more than 500 hours, linear flow was the dominant flow regime and therefore the final radial flow stabilization had not yet been reached.There are many studies in the literature on the design, operations, characterization and numerical modelling of similar multifractured horizontal wells. However there are not many publications presenting real field data and the performance of these wells. This paper covers the well performance data in addition to the design, modelling and operations of the multi-fractured horizontal wells.

This paper provides a study of a history match on a complex reservoir model using a global optimization method. This is done by applying Evolutionary Algorithms to the problem of history matching. The results of the history match are then used to carry out an uncertainty assessment on variables of interest. The main parameters used in the history match included: horizontal permeabilities, porosities and vertical transmissibilities. This study also made use of methods for improving the convergence of the optimization cycle, which included using correlations, adopting a Bayesian approach and exploring the search space. The results obtained over the optimization cycle, are used to identify sensitivity parameters, correlations and parameter trends in a global search space. In addition the original manual history match was further improved by adopting a pressure match using an Evolutionary Strategy. Best matched cases were selected based on the global and partial objective values of each match. Predictions runs were performed in order to investigate the effect on the cumulative oil produced and the STOIIP. Finally an uncertainty assessment of the most recent history match was carried out using an experimental design matrix. The results of the experimental design were used to generate a proxy, which is used in a Monte Carlo simulation to develop P10/P50/P90 oil forecasts. Introduction The focus of this study is to assess the Valhall field reservoir simulation model using Evolutionary Algorithms and uncertainty assessments, in order to improve the manual history match of this model; this is done in turn to increase the reliability and confidence of the simulation model utilized by Total E&P Norge AS and its partners. The Valhall field is a complex field with rock compaction as its main energy drive. This contributes to many challenges which include the reduction of porosity and permeability with time and the continued change of the reservoir thickness due to compaction. The compaction can also affect different parts of the reservoir differently, for example the reduction in the pore volume of one region due to compaction can vary from other regions. This can cause many problems to the history matching process, in which changing a particular parameter can have opposite effects on a well or region, therefore, it is extremely difficult to history match this type of field. Other challenges include a variable production profile due to well instabilities, chalk production and downtime, which contribute to the history match and prediction complications. An Evolutionary Algorithm will be utilized in order to enhance the history match of this field. This algorithm will assist in exploring different methods and strategies that have never been tested on this field before. The algorithm will be used as part of the relatively new software, Multipurpose Environment for Parallel Optimization (Mepo®). Quantification of uncertainty is common practice and the most important parameters should be assessed over a range of uncertainty. Uncertainty assessment in the past has been slow and inefficient; it was normally done by varying one parameter at a time and running simulations, in order to assess the results[15]. One of the most important uncertainties is the oil production forecasts which are evaluated as the oil recovery factor or the cumulative oil production[14]-[21], another important parameter is the Stock Tank Oil Initial in Place. In order to increase the acceptance of the results from the history match, the uncertainty of the history match has to be quantified. Oil, water and gas production forecasts for economical decisions are normally carried out. Important decisions, such as well placement and locations are made with respect to the predictions conducted using the history matched reservoir model, and therefore, it is important to implement an uncertainty assessment to such models. The results from the optimized history match model are used to create the Experimental Design Matrix (EDM). The uncertainty assessment was carried out using MEPOrisk® software, still under development by Scandpower Petroleum Technology. Figure 1, shows the uncertainty assessment workflow carried out using MEPOrisk®.

This paper describes the design and interpretation of interference tests conducted between injectors and producers in the Huntington oilfield. The field is located in the UK Central North Sea and developed with four horizontal producers and two inclined water injectors. Water injection provides reservoir pressure support and mitigates the uncertainty of aquifer strength and its connectivity to the oil leg. This ensures adequate pressure maintenance in support of hydrocarbon recovery. It is important to understand effective communication between the wells. This is required to improve the forecasts of water breakthrough, to plan preventative actions and to optimise field operations and reservoir management. Therefore, a series of modified pulse tests were performed during the clean-up and well test campaigns to minimise disruption and delay to the drilling schedule. Data were recorded using permanent down-hole gauges installed in the horizontal producers, and the analyses of the results were performed using both analytical and numerical models. The modified pulse tests confirmed good communication between the producers tested. A reasonable match between the modified pulse test data and simulation model predictions is demonstrated in this paper, where reservoir properties such as permeability and porosity estimated for the inter-well areas show good agreement with the well test results. The test between injector and producer was also used to match the pressure response and can be used to predict injection water breakthrough. In the test, water was injected into two different intervals, the Upper and Lower Forties. Comparison of the injection test results with numerical simulation data suggests that no communication exists between these two intervals. This is a practical example of interference testing which provides insight and assurance on effective reservoir properties on an inter-well scale. This kind of data, before field start-up and free from the influence of other producers, is very useful for the field performance prediction and also rarely available in the literature. Introduction Interference tests were first introduced by Jacob (1940) for water wells and later demonstrated for use in petroleum engineering by Elkins (1946). Driscoll (1963) then outlined the use in the petroleum industry to obtain average areal reservoir transmissibility, storativity and degree of communication between wells. For interference testing of horizontal wells, Malekzadeh and Tiab (1991) provided type curves and direct analysis methods for an isotropic medium. Johnson et al. (1966) introduced pulse tests; a modification of interference tests, where the active well flow rate is changed several times to form a series of alternate flow and shut-in periods instead of a single producing constant rate. This was analysed using the tangent method to determine the time lag, tL and response amplitude, ?p. It was initially believed that durations for pulse tests would be shorter compared to interference tests. However, Kamal (1983) showed that the testing times remained the same for both pulse tests and interference tests if the same type of pressure gauges were used but the shut-in time for pulse tests is less. This is the main advantage of the pulse tests, where a long shut-in duration is not required to record pressure data.

Reservoir characterization of laminated turbiditic sequences is often problematic due to the highly anisotropic setting, which affects the formation evaluation from conventional LWD, wireline logs and mudlog data. The reservoir, fluid content and pay petrophysical parameters are usually underestimated. Time and cost constraints can prohibit the utilization of new generation high resolution tools and to perform conventional DSTs. An oil and gas bearing well in deep water Indonesia was accurately evaluated with a relatively low time and cost investment in formation evaluation and data acquisition. Pay, porosity and water saturation were calculated by integrating high resolution image logs with standard wireline logs. An ample dataset of reliable formation pressures and fluid samples were obtained in a thin bed environment from Wireline Formation Testing (WFT) utilizing standard and large size probes. Mini DSTs were carried out to characterize reservoir and fluid properties. Thin beds were recognized using an imaging log in oil base mud and through a Thin Layer Analysis (TLA) approach the net sand calculation was enhanced. The TLA result was cross-checked with an electrofacies profile obtained using standard well logs (density, neutron and gamma ray) and calibrated with the sedimentological core description from other wells. In the final net sand computation beds not corresponding with actual reservoir facies were not considered so that only the effective reservoir was included. The result of this integrated approach resulted in an increase in the net pay evaluation in comparison with the conventional formation evaluation, and confirmed the high potential of nonconventional pay in a deep water environment. An exhaustive reservoir and fluid characterization was also achieved without coring and conventional DSTs.