In the offshore environment, options to regain control over a blownout oil or gas well directly from surface, e.g. by capping are limited, particularly in the case of subsea wells or underground blowouts. Hence injection of a kill fluid via a relief well will often be the only alternative. In view of offshore logistics and cost of such an operation, this requires reliable estimates for the kill rate, pump pressure, hydraulic horsepower, kill fluid density and volume, prior to spudding relief well(s) and arranging for the pump equipment, fluid make-up plants and storage capacity. Various methods to estimate these parameters have been proposed. Validation of the methods has been very limited however since an actual blowout situation, with all inherent uncertainties (e.g. with respect to blowout well performance) does usually not allow a thorough kill job evaluation. To close this gap between theory and practise, a dedicated full scale field test to study how a dynamic well kill proceeds in a high rate gas well, has been designed, executed and analysed. Through variation of the blowout and kill rates, conditions under which the well ceased flowing could be determined accurately. Valuable insights on the processes taking place in the well during the kill were obtained. Analysis of the test results shows the correct methodology to predict the parameters for a successful and efficient kill job. P. 103

Summary Many deepwater-development projects in operators' portfolios require lower costs to meet internal economic thresholds. Because of this, Shell has looked at extending surface-blowout-preventer (BOP) activities to include well testing and completion techniques for deepwater wells in conjunction with surface-BOP drilling. The cost advantages of surface-BOP-drilled wells have been demonstrated(notably in the Far East), but the recent surface-BOP-drilled well in Brazil is a milestone in terms of extending the applicability to deeper water and harsh erenvironments. The enabling technology has been the subsea isolation device(SID).Testing and completion techniques have been developed to be compatible with surface-BOP wells drilled with an SID. This paper focuses on the following aspects:•Well testing using surface-BOPs from a moored rig and•Well completions using surface-BOPs from a moored rig. Shell has developed a testing configuration to carry out a DST, essentially using standard equipment. The well-testing equipment configuration is currently ready for use and has been run in a subsea-BOP well. In completion operations, the availability of a high-pressure (HP) riser does not add significant complexity and even actually simplifies some of the completion activities. Conceptual studies and early hazard/risk assessments have shown there are no obvious "showstoppers," and the duration of a surface-BOP-rig completion is expected to be very similar to a subsea-BOP-rig completion. This paper describes the results of the conceptual studies, early hazardassessment exercises used to define the basic design parameters, and more detailed hazop studies. Introduction As deepwater exploration and development move into even deeper water and more arduous environments, operators are looking at ways to reduce well costs to make prospects and developments economically more attractive. One of the key avenues seen to do this is to accomplish drilling, testing, and completing wells by use of smaller deepwater rigs, consequently resulting in a reduction in rig rates. Surface-BOP technology facilitates the deployment of smaller rigs in deeper water, thus lowering day rates, well costs, and field-development costs. To date, most ultradeepwater wells (in which water depth is greater than5,000 ft) have been executed using the latest generation of new or converted drilling vessels (these will be referred to as "Generation V" rigs).Over150 subsea wells in varying water depths have now been executed with floating rigs with surface-BOPs in locations around the world. In 1967, a semisubmersible rig (Sedco-135) was used to drill a subsea well by use of surface-BOPs offshore Nigeria in EA-3.Since then, a number of operators have pioneered the use of surface-BOPs with moored rigs in the benign environmental conditions of the Far East. Shell has recently used surface-BOPs on a Generation V dynamically positioned (DP) rig to extend the7,500-ft-water-depth capability of the rig—drilling a deepwater exploration well in 9,474 ft of water offshore Brazil.1 The trend is to take this technique and apply it in a number of deepwater-operating areas with older Generation III and IV rigs that were not specifically built for deepwater operation. This paper outlines the well-testing and well-completion approaches that are planned to meet these challenges. The overall surface-BOP system will be described followed by the description of well-testing and well-completion methodologies. It should be noted that these methodologies are continuously worked on and refined; once actual experience is gained, they will, of course, change and be further optimized.

The reliability of the production is essential in offshore operations. Producing a well at its maximum rate is important everywhere. This is often compromised by having sand and fines production which not only plugs the wells and reduce production rate but also erode the equipment and settle in surface vessels. This paper describes a case history where an operator was faced with a well that was rate limited because of fines and sand production. An advanced sand control chemistry system was proposed and a treatment was designed. In April 2013, the treatment was performed by bullheading down the production tubing using rate diversion. Extensive engineering was involved in the candidate selection and planning the operational aspects of the treatment. The execution of the treatment was divided into stages – sand clean out, performing step rate test, pre-job modeling and pumping the treatment as per the design. After the treatment, the well was flowed and tested at almost three times the original maximum sand-free rate (MSFR) at an increased choke without sand production. The well has now been flowing for more than a year, at significantly higher rate than the previous MSFR sand free. This paper describes the chemistry of the sand conglomeration, design consideration, execution and the effect on well performance.

Field development planning for an asset requires close interaction between different domains and departments, to reduce any potential uncertainties within the studied asset. Reducing uncertainties is crucial in investment preparation for a new green field development. By adopting an integrated asset approach, such cross-department interactions can be further improved by breaking down the barriers and assembling an integrated asset team with a common goal. This paper summarizes the construction of an integrated asset study for an offshore green field and compares the study against those obtained from the standalone-domain models. In this study, a reservoir simulation model was coupled to the wells and network models, which were further integrated to the processing facilities models and the asset economics evaluation model.The aim of the study was to evaluate an existing field development plan (based on the traditional standalone approach) with an integrated asset approach to identify any possible constraints and potential deviations, enabling proactive actions to be taken on the asset management for future operations. The work presented here encompasses the use of various numerical simulation software applications working together in a single simulation environment, which allowed sensitivity analysis on different elements of the asset and evaluation of any possible impacts among the studied elements, such as manifold choke sizing and gas lifting parameters.This assessment consists of a study from reservoir to economics, taking into account of wells, pipelines, surface equipment, production networks and downstream process facilities. The study demonstrated any components of the production network system and topside operating condition could impose constraints on the reservoir deliverability. Apart from evaluating various operating scenarios to best utilize the emerging capacity and to investigate back-out efforts and other challenges during the field development, it also provided guidance on how to further optimize the production system in terms of finding choke sizes over time and adjusting gas lift injection according to gas availability and operating pressure constraint. With its integrated asset approach, this study also presented a base case that could be extended with inclusion of gas lift distribution system to enable a more comprehensive analysis and asset field development study.

The proportion of new wells requiring sand control is increasing, and choosing the most economic sand control system from the available options is a central component in field development planning. The choice of sand control system depends on a number of factors such as production and sand control performance, reserves recovery, reliability, ease of installation and life cycle economics. Logistical and HSE issues are also becoming increasingly important, especially in areas with limited support infrastructure. A key input to the process of sand control system selection is data on how the various systems compare in a given environment. Ideally, this comparison should be made over time in order to properly compare the long term performance and reliability. This data can only be obtained by analyzing existing installations equitably and objectively. The Mokoko-Abana field is situated offshore Cameroon. It is a mature heavy oil field with unconsolidated formations that require sand control from the onset of production. A wide variety of sand control solutions have been used in this field, although with varying levels of success and performance. Cased hole internal gravel packs (IGP), milled casing openhole under-reamed gravel packs (MCGP) and cased hole frac-packs (CHFP) have been used in vertical wells. Prepacked stand-alone screens (PPSAS), openhole gravel packs (OHGP) and openhole expandable sand screens (OHESS) have been used in horizontal and highly deviated wells. Each of the completion options now has several years of production history. This allows the initial performance and the performance over time to be modelled and compared. The wells chosen for study were in the same sand body with as near perfect installation as possible. The MCGP had relatively good performance as did the CHFP, unfortunately however the CHFP fractured into a water bearing leg and only added water cut. The PPSAS had initially low mechanical skins, but its performance declined quickly. The OHGP had higher initial skins but the rate of production decline is much slower. The OHESS had a very low initial skin with no impairment over the five year production period. SPE 946511contains background information on the Mokoko-Abana field, and looks at the productivity performance of the PPSAS, OHGP and OHESS techniques on initial completion and after two years of production. This paper follows on from SPE 94651 and examines the operational, productivity, reliability and economical aspects of the completion techniques over five years or more of production. Introduction A comparison of the performance of sand control completions in the Mokoko-Abana Field was carried out in 2004 and 2005. This compared three wells completed on the same oil sand with essentially the same hole size, similar drilled trajectories, similar drilling mud, the same rig and with largely the same personnel. All were successfully executed and can be considered as fair and reasonable comparisons. Each well had(then) at least two years production history. Differences in reservoir properties, artificial lift method and minor differences in fluid characteristics were modelled and backed out.