Africa (Sub-Sahara) Bowleven began drilling operations at its Zingana exploration well on the Bomono permit in Cameroon. Located 20 km northwest of Douala, Cameroon's largest city, the well will target a Paleocene (Tertiary) aged, three-way dip closed fault block. The company plans to drill the well to a depth of 2000 m and will then spud a second well in Moambe, 2 km east of Zingana. Bowleven is the operator and holds 100% interest in the license. Asia Pacific China National Offshore Oil Company (CNOOC) has brought its Dongfang 1-1 gas field Phase I adjustment project on line ahead of schedule. The field is located in the Yinggehai basin of the Beibu Gulf in the South China Sea and has an average water depth of 70 m. The field is currently producing 53 MMcf/D of gas and is expected to reach its peak production of 54 MMcf/D before the end of the year.
This study presents an approach to determine the dimensions of three-phase separators. First, we designed different vessel configurations depending on the fluid properties of an Iranian gas/condensate field. We then devised a comprehensive computational-fluid-dynamics (CFD) method for analyzing the phenomena of three-phase separation. The results in terms of separation efficiency and behavior of secondary-phase particles were reviewed to choose the optimal configuration. Only a slight difference in the length of this vessel and the existing separator was found. In addition, simulation data were compared with industrial data pertaining to a similar existing separator. The results of this work showed that the CFD model used is capable of investigating the performance of three-phase separators.
This paper presents a comparative study of two commonly used three-phase separator design procedures; Arnold and Stewart and Svrcek and Monnery. The procedures were developed based on droplet settling and retention time theories for the separation of gas, oil and water and are known to predict different separator geometries for the same operating conditions. These procedures were constrained to allow optimisation of the design but details of the constraints applied on the rational for their application are not available. To better understand these constraints, the two procedures for sizing a three - phase horizontal separator equipped with weir plate were investigated. Each procedure was used to calculate the geometries for three different sets of flowrates namely; fixed oil with varying gas and water, fixed water with varying gas and oil and finally fixed gas with varying oil and water. The calculated geometries determined from each procedure were then investigated using ANSYS Fluent to determine the separation achieved. To ensure that the ANSYS Fluent simulations accurately defines the separation process, a small scale industrial separator was modelled. Simulation results in terms of the separator outlet quality predicted that the separator designed using Arnold and Stewart procedure has a greater separation efficiency than that designed by Svrcek and Monnery.
The Chestnut field produces from two subsea, non-isolated commingled wells tied back to the Hummingbird FPSO. A steep decline in production was observed in Q1 of 2014 in well 22/2a-11x which was attributed to the formation and deposition of barium sulphate scale in the well and confirmed through a new method developed for the determination of seawater breakthrough onset in commingled wells (Chen 2015). Following this, an elevated temperature barite dissolver treatment was designed so as to try and remove the scale and allow for a subsequent scale squeeze treatment to be applied. Deployment of the dissolver and scale squeeze treatments, however, presented several challenges, the main one being that the 22/2a-11x well cannot be mechanically isolated from the other well in the field for a treatment to be bullheaded. In addition, the common flowline was known to contain sand and the well's xmas tree design and vicinity to the FPSO meant that any chemical treatments needed to be delivered down the production riser; the limited deck space on the FPSO rendered this a particularly complex operation. A supply vessel had to be modified to accommodate mixing, storing and heating capabilities, with heated dissolver being transferred to the FPSO via a suitably rated hose over open water. A unique delivery approach was developed to allow the successful placement of the scale dissolver and scale squeeze treatments in well 22/2a-11x through the use of a non-aqueous liquid plug in the common flowline; the combined treatments led to a doubling in the well's production compared to oil rates prior to the intervention. This paper presents the difficulties associated with delivering these multistage treatments and the applied engineering solutions that enabled effective placement of both the scale dissolver and scale squeeze in this subsea well. In addition, lessons learned in the process as well as an evaluation of the placement strategy on the efficiency of the scale removal and squeeze treatments will be discussed.
Ibukun, Opeyemi (Innovative Engineering Systems Global) | Tovar, Juan (Innovative Engineering Systems Global) | Heinemann, Niklas (Innovative Engineering Systems Global) | Chalmers, Frances (Centrica Energy) | Mokdad, Belkhir (Centrica Energy) | Katoozi, Kia (Taqa)
Reservoirs in the Niger Delta oil province are predominantly weak sandstones and unconsolidated sands of the Agbada formation. Wells in these reservoirs are susceptible to sand production as production entails high water cut. Sand production is triggered by mechanical failure near the wellbore and occurs when the near-well deformation process changes. The deformation process is controlled by parameters such as production rate, drawdown, reservoir pressure changes and reservoir formation properties. Mechanical failure of the reservoir leads to the mobilisation of failed material and changes the near wellbore porosity and permeability of the rock.
The Chestnut Field operated by Centrica Energy and partners (block 22/2a, Central North Sea, UK sector) has been under production since 2008 despite continuous sand production. The reservoir consists of unconsolidated sand with a porosity average above 30% and permeability of 0.5 to 2 Darcy similar to many Niger Delta sand reservoirs. This paper introduces the Sand Production and Pore Pressure Management Program which was implemented to control sand production and maintain hydrocarbon production. Additionally, an analysis of near wellbore porosity and permeability changes is presented.
Real-time data acquired from four wells over a period of more than four years and the production of over 140 tons of sand were utilised. The results indicate a change in porosity and permeability which is consistent with a change from compaction to dilatancy conditions near the wellbore. These changes have had a significant impact on the sand management strategy implemented to optimise the production through the field life to date.
So far, oil and gas production in the deepwater Gulf of Mexico is mostly from Neogene (Pleistocene, Pliocene, and Upper Miocene) reservoirs. The Neogene reservoirs can be characterized broadly as overpressured, unconsolidated, and highly compacting, with high permeability and containing black undersaturated oil of medium gravity with moderate gas/oil ratio and some aquifer support. Although waterflooding is a mature technology, few water-injection projects have been conducted in the Neogene reservoirs because they exhibit good primary recoveries, exist in high-cost offshore environments, and are relatively small. In some of these fields, a limited volume of water was injected.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 24111, "Water Injection in Deepwater, Overpressured Turbidites in the Gulf of Mexico: Past, Present, and Future," by X. Li and K.K. Beadall, SPE, Knowledge Reservoir; S. Duan, SPE, Chevron Corporation; and J.R. Lach, SPE, Knowledge Reservoir, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed.
Good primary recovery, high drilling cost, and facility limitations mean water injection is not commonly used in the deepwater Gulf of Mexico. However, waterflooding can supply additional reservoir energy for producing substantial quantities of oil trapped by limited displacement drive and poor sweep efficiency. This paper is a detailed examination of Pleistocene-to-Upper- Miocene turbidite reservoirs in the deepwater Gulf of Mexico under water injection. Waterflooding strategies have proved to be highly effective in achieving good incremental oil recovery from these reservoirs.
So far, oil and gas production in the deepwater Gulf of Mexico is mostly from Neogene (Pleistocene, Pliocene, and Upper Miocene) reservoirs. The Neogene reservoirs can be characterized broadly as overpressured, unconsolidated, and highly compacting, with high permeability and containing black undersaturated oil of medium gravity with moderate gas/ oil ratio and some aquifer support. Although waterflooding is a mature technology, few water-injection projects have been conducted in the Neogene reservoirs because they exhibit good primary recoveries, exist in high-cost offshore environments, and are relatively small. In some of these fields, a limited volume of water was injected.
In 2008 the Minerals Management Service, now the Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement BOEM/BSEE in partnership with the National Oceanic and Atmospheric Administration (NOAA) and the National Oceanographic Partnership Program (NOPP), sanctioned a deepwater study in the Gulf of Mexico. Officially designated as the Deepwater Program: Natural and Artificial Hard Bottom Habitats with Emphasis on Coral Communities: Reefs, Rigs and Wrecks "Lophelia II", it is typically referred to as the "Lophelia II" Project. A substantial component of the contract was the examination of several deepwater shipwrecks. The "Wrecks" component of the project called for the archaeological examination of several shipwrecks as a continuation of the 2004 Deepwrecks Study in the Gulf of Mexico. These wrecks covered a broad time period from 19th century wooden sailing vessels to World War II era vessels. Between 2008 and 2010 three field seasons incorporated shipwreck investigation cruises that culminated in an Archaeological Assessment Report submitted as part of the larger Lophelia II Project Draft Report submitted to BOEM/BSEE in 2013. This presentation will provide a final analysis of the Lophelia II shipwreck sites based on data acquired between 2008 and 2010. In addition to the shipwreck findings, it will also present an analysis of the project itself and provide recommendations for future deepwater shipwreck studies of this type.
The first Tension Leg Platform (TLP) was installed in 1984 to develop the Hutton field in the Central North Sea in about 500 ft of water. It successfully demonstrated the ability of a floating platform tethered to the seabed to drill and produce with surface trees. In the ensuing years, twenty three additional TLPs have been installed and five more sanctioned, in most major deepwater producing regions around the world, in water depths down to 5,200 ft.
The TLP today is a mature and proven deepwater production platform and is routinely included as a platform concept building block for many deepwater prospects during field development planning for dry or wet tree scenarios. This paper will present a retrospective of TLP development that includes:
This paper highlights the progression of TLP technology and contracting strategies of the installed and sanctioned TLPs. The paper provides a snapshot in time to capture the evolution and current state of TLP technology. The impact on TLP design in Gulf of Mexico (GoM) from the new API RP 2T is demonstrated via an example of a pre and post Katrina sanctioned TLP.
TLP System and Hull Configuration Overview
The TLP is one of several mature floating production platforms in the Offshore Industry's arsenal to enable development of deepwater fields in any openwater offshore producing region in the world. It was conceived in the 1970s as a means of enabling direct vertical access to wells in water depths beyond the commercial reach of fixed and compliant platform capabilities. Fundamentally, it consists of a buoyant hull, which supports the topsides and well systems, anchored by rigid tendons to a seabed foundation to restrain vertical motions in waves. Excess buoyancy pretension the tendons that limit the horizontal offset to a prescribed watch circle. The heave restraint enables production wells to be tied back to the TLP deck by tensioned vertical risers to "dry?? trees. The dry tree facilitates easy downhole access for well intervention and reservoir management to maximize hydrocarbon recovery from a reservoir. This is particularly applicable for highly compartmentalized and stacked reservoirs. It also simplifies running and retrieval of downhole electric submersible pumps (ESP's) to further boost well production rates and ultimate recovery. Major TLP components are illustrated in Fig. 1.
Introduction The Bakken petroleum system is an unconventional tight oil play containing both source and reservoir rock, with continuous saturation throughout much of the Williston basin in North Dakota and eastern Montana. With a continuous-type accumulation, and increased thickness of a source and/or reservoir rock can mean (1) an increase in hydrocarbons generated and expulsed from the source rock, and/or (2) an increase in storage capacity within the reservoir rock. For this, and other reasons yet to be presented, thickness anomalies within the Bakken and Three Forks formations are of great interest to hydrocarbon exploration and production in the Williston basin. Thickness anomalies have long been recognized in Devonian and Mississippian strata of the Williston basin in North Dakota and Montana, and the Canadian provinces of Saskatchewan and Manitoba. Dissolution of Prairie salt, collapse of overlying beds, and infill of the resultant accommodation space has been cited as one mechanism for the creation of thickness anomalies in the Williston basin (Anderson and Hunt, 1964; Demille et al., 1964; Holter, 1969; Langstroth, 1971; LeFever and LeFever, 2005; Oglesby, 1988; Parker, 1967).