Multiphase flow correlations are used to determine the pressure losses incurred as a result of fluid flow through pipe. This evaluation is necessary since energy is ultimately lost as a fluid moves through pipe. These losses are incurred due to frictional losses, acceleration and the effects of the fluid weight for vertical flow. The predicted vertical tubing pressure drop for twenty-three (23) gas wells, using fourteen (14) multiphase flow correlations, were compared to measured field data. The results were analyzed to determine suitability and accuracy for varying reservoir and fluid characteristics such as gas rate, condensate gas ratio (CGR), water gas ratio (WGR), tubing size, age and angle of inclination for three Trinidad southeast coast gas fields; Field A, Field B and Field C. These fields are owned and operated by bp Trinidad and Tobago LLC. A total of two hundred and eighty (280) well tests were used for the analysis and this amounted to 3920 data points.The results obtained showed that none of the correlations used to predict the tubing pressure losses perfectly matched the measured field data. The percentage error (pressure) was calculated and together with other criteria, was used to recommend which of the correlations would be most appropriate for use in each of the three fields under specific conditions. The analysis conducted showed that the Gray correlation met all the specified criteria and is the recommended correlation to be used in all fields.

A 600K Hydraulic Workover (HWO) Unit has proven that it has the capability to safely access and deliver offshore gas reserves. This paper identifies the business environment, challenges, learnings, results and the key success factors of a three (3) well project that delivered a total of 250 million standard cubic feet per day (mmsfcd) using a 600K HWO unit. The primary result of the project demonstrated the capability of the HWO unit in handling challenges previously thought better suited for conventional larger rigs. HWO units have proven to be particularly effective in bpTT's offshore operations, however their application had been limited to tubing changeouts, workovers, oil recompletions and short oil sidetracks. This project expanded the capability of the 600K HWO unit to perform high rate uphole gas recompletions. The project consisted of three uphole gas recompletions in 9-5/8 inch casing. Each recompletion was executed at approximately $0.50/barrel of oil equivalent (boe) which made the project extremely attractive and made gas reserves economically viable. Completing the same work with a larger Jackup unit would have cost $3 -4/boe clearly showcasing the economic advantage of the HWO unit. Another major advantage was the ability to move the HWO unit in unfavourable weather conditions when compared to a Jack Up rig. Weather conditions can result in significant and costly delays during the December -April period for jack up units.

Rate dependent skin is a key factor influencing the deliverability of gas producing wells because of the phenomena of high velocity flow behavior around a limited, near wellbore cross-sectional area. Forchheimer (1901) [1] proposed an additional factor in Darcy’s original equation to account for the pressure drop due to high velocity flux in the porous media, known as "Inertial Resistance Factor (β)", which is now a determinant parameter in the flow modeling of gas wells. Several authors have developed different correlations that account for the inertial forces acting under these producing conditions. Multi-rate and Pressure Transient Analysis (PTA) evaluation was performed on nine (9) gas well tests in the Dolphin Field. The Non-Darcy Flow Coefficient (NDFC) obtained was compared with predicted NDFC’s using 18 Beta (β) correlations, where each correlation has its own assumptions and determinant parameters. Existing correlations do not match the actual NDFC in the field, as a consequence, a new Inertial Resistance Factor Correlation (IRFC) is proposed for assessing the unknown NDFC in the ECMA fields with a minimum percentage error of 17%. The following study will detail the results of a probabilistic approach which uses correlations to provide a better estimate of NDFC in the Dolphin field, with the final objective of reducing uncertainty in forecasting production on recompletions and new wells in East Coast Marine Area fields.

Calculating and determining a range of Gas Initially In Place (GIIP) is one of the major challenges faced when optimizing a field development plan. Desired outcomes can be further complicated by geological characteristics which are uncertain and difficult to quantify; to the point where a physical solution is unattainable without the use of inappropriate and complicated software applications. Plackett-Burman Experimental Design (P-B ED) is a published and an innovative process which is simple, logical and efficient in managing uncertainty and appropriately defining the range of possible outcomes by utilizing simple, every day and user friendly software. PB ED allows for effective planning and mitigation for the most likely outcome and the least. The geological uncertainties incorporated in the analysis are described in Part 1 of the Greater Dolphin Area Case Studies; SPE 158545. The P-B ED workflow was applied to determine the range of GIIP for the Starfish field. Starfish is currently not on production and is located off the East Coast of Trinidad and is being considered for development. It is owned as a joint venture between Chevron and BG Trinidad and Tobago (operator). One of the main objectives of this process was to identify the P10, P50 and P90 geo-models which are then used for dynamic modeling and field development planning. The Unconstrained Development Study (UDS) process was utilized for the field development planning of Starfish. A UDS is a process used to determine the optimum number of wells and their locations to develop a field. The P50 dynamic model was populated with hundreds of wells which were subsequently eliminated based on well performance and water breakthrough. This is an iterative process which has been recognized as an effective workflow for field development planning. Once the P50 reservoir outcome was optimized, both P10 and P90 geo-models were tested to ensure that the proposed development plan was also valid for the geological range. After applying the UDS process; it was determined that four wells were required to optimally develop the field. This paper discusses the Experimental Design and UDS workflows, summarizes the lessons learned and recommends best practice for field development optimal recovery efficiency.