Uncertainty in permeability anisotropy proved to be one of the key factors while evaluating the performance of horizontal/deviated wells in the field under study. This gas condensate field, located in the UKCS of the North Sea, has sands of varying quality. All wells are producing below the dew point with a liquid condensate bank developing early in the life of the well, affecting productivity. Drilling horizontal and highly deviated wells to increase PI was considered a viable approach. However, the performance of such wells depends highly on permeability anisotropy; data was scarce and available only from core, limiting the scale of investigation. This paper describes the investigation of permeability anisotropy in selected layers in the reservoir. Open hole vertical interference tests were conducted at five reservoir zones with a wireline formation tester using multiple probes. The tests were analyzed using an analytical model, which simulates the pressure response at an observation probe vertically displaced from the active probe. Four tests showed a clear response where horizontal and vertical permeabilities were computed. The favorable anisotropy figures obtained from analyzing the Modular Formation Dynamics Tester (MDT) data gave increased confidence about associated PI improvements from highly deviated wells. With this information, highly deviated wells were incorporated within the near term drilling program. Introduction Five multiprobe tests were conducted using the Modular Formation Dynamics Tester (MDT). The tester1–12 can combine multiple probes and/or a dual inflatable packer to conduct transient tests along openhole. The tester is also widely used for taking formation fluid samples. Figure 1 shows some of the possible configurations of the modules, which can be used for vertical interference testing. The tests start with setting all probes and/or dual packer module and performing pretests at each location to confirm the seal from wellbore pressure and to measure the initial pressure. These pretests also provide information on the mobility near the wellbore. Following the pretests, a flow rate source is used to produce formation fluids through the active probe or dual packer interval to create pressure transients. The flow rate source can be the pumpout module, the 1–liter flow control module or various sample chamber modules. The resulting pressure responses at the active point of fluid withdrawal and at observation probes are measured using high-resolution quartz and strain gauges. The analysis of these transients gives horizontal and vertical mobilities, generally within tens of feet away from the wellbore. In this study, results from five multiprobe vertical interference tests will be summarized. The objective of the data acquisition and interpretation program was to quantify the vertical and horizontal permeabilities within selected sand bodies to assess the performance of deviated and horizontal wells in this field. Reservoir Description This Lower Cretaceous sandstone reservoir is typically 600 ft thick with correlatable sandstone units separated by shales. The sands show characteristics of high-density turbidity currents, debris flows and slurry flows. The main facies are debris flow sands, high-density turbidites, liquefied sands, banded and laminated sands with laminations and banding on a varying scale. The reservoir quality is directly linked to facies type but has been downgraded due to various types of mineral cements, clays and deep burial. The quartz and calcite cements and chlorite and kaolinite clays are the main contributors. The liquefied sands and debris flow sands have high detrital clay content and poor sorting. The laminated facies have intermediate reservoir quality and the best reservoir quality sands are the clean turbidite sands. Figure 2 shows the different sand facies types. In general, the field has moderate porosity and permeability, ranging from 5 to 18 pu and 0.1 to 100 md respectively.

The Britannia field is a gas producing reservoir operated jointly by Chevron and Conoco. Prior to completion of the wells, two major concerns were raised: potential sand production (perforation stability), and the optimum underbalance (for zero perforation skin) during completion. Theoretical models were used to predict the optimum underbalance based on log derived formation properties. Using detailed log permeability data numerous simulations were carried out to choose the gun, charges, shot density and perforating strategy for optimum productivity. Different shot densities and charges were used in different sections of the formation based on simulation results as opposed to choosing perforation parameters based on average well properties. Experiments were conducted to confirm the theoretical underbalance predictions and to investigate the stability of perforation tunnels at high underbalance pressures. Reservoir and outcrop core samples were perforated at simulated down hole conditions in the laboratory at different underbalances based on values obtained from the model. Flow performance evaluation of the perforated reservoir core samples confirmed earlier conclusions on the sensitivity of the formation to aqueous wellbore fluids (brine). The results also confirmed the stability of the perforation tunnels at high underbalance. An underbalance value of 1000 psi used in the outcrop sample tests indicated near zero perforation skin. Perforation strategy for the North Sea field was chosen based on the results from the study. Well performance analyses of 12 of the wells completed indicate low to negative skins. The information is presented in this paper as a case of how to design a good perforating job and also to emphasize the need to study optimum underbalance for gas formations. Introduction The Britannia field is a gas-producing reservoir operated jointly by Chevron and Conoco. Prior to completion of the wells, two major concerns were raised: potential sand production, and the optimum underbalance (for zero perforation skin) during completion. In addition an overall perforating strategy was desired as this has a major impact on well productivity. In general, there are four key aspects to perforating that play an important role in determining the productivity: perforation dimensions (length and diameter), shot density, phasing and perforation damage1. The choice of gun parameters to optimize the completion is usually carried out using theoretical analysis of the efficiency of the completion (or gun choice) using inflow/nodal analysis programs2. For the current study the variation in lithology was taken into account instead of the general procedure of average reservoir properties. Log and core data was used to determine the productivity of different layers based on their conductivity and formation damage. For each layer numerical productivity simulations were carried out to determine the optimum perforation parameters: shot density, penetration and underbalance conditions (an acceptable phasing was fixed). The best method to minimize perforation damage is by underbalance perforating3. Theoretical guidelines are available which can determine optimum underbalance (zero perforation skin). The most frequently used optimum underbalance relationships are based on single-shot perforation and flow tests with oil saturated samples3. Very few tests or studies have been conducted to study perforation performance in gas saturated core samples4,5. In addition use of the theoretical models can lead to high underbalance pressure requirements in strong low permeability formations. This issue was addressed in this study by single-shot perforation and flow experiments in reservoir rock and outcrop rock simulating down hole stress and flow conditions. One of the concerns during underbalance perforating is the potential for sand production (or collapse of perforation tunnels)6. This was also addressed using the single-shot perforation and flow studies. The experiments were conducted in the Advanced Flow Laboratory in Schlumberger Reservoir Completions Technology Center.

The Britannia field is a gas-producing reservoir operated jointly by Chevron and Conoco. Before completion of the wells, the major concern was the optimum underbalance to obtain zero perforation skin during completion. Theoretical models were used to predict the optimum underbalance based on log-derived formation properties. With detailed log permeability data, numerous simulations were carried out to choose the gun, charges, shot density, and perforating strategy for optimum productivity. Different shot densities and charges were used in different sections of the formation based on simulation results, as opposed to choosing perforation parameters based on average well properties.Experiments were conducted to confirm the theoretical underbalance predictions at high underbalance pressures. Reservoir and outcrop core samples were perforated at simulated downhole conditions in the laboratory at different underbalances based on values obtained from the model. Flow performance evaluation of the perforated reservoir core samples confirmed earlier conclusions on the sensitivity of the formation to aqueous wellbore fluids (brine). An underbalance value of 1,000 psi used in the outcrop sample tests indicated near-zero perforation skin. A perforation strategy for the North Sea field was chosen based on the results from this study. Well performance analyses of 12 of the wells completed indicate low to negative skins. The information is presented in this paper as a case of how to design a good perforating job and also to emphasize the need to study optimum underbalance for gas formations.