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.
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.
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).
The proper handling and processing of crude oil systems plays an important role in the economics of crude oil production. The separator is the first processing equipment for crude oil systems. Separator design procedures are cumbersome, time consuming, involve a lot of guesswork, and are prone to a lot of human calculation errors. Furthermore, subjectivity arises with each design procedure on the parameters necessary and crucial for separator design. Hence, there's a need to develop a user-friendly computer program to automate separator design. Separator design is based on empirical procedures that have been established based on sound engineering judgment.
In this work a user-friendly computer program was developed to estimate separator dimensions (diameter and height). Two design procedures, Svrcek and Monnery 1994 and the modified Arnold and Stewart 2008 were selected based on the parameters used in their design procedures. The equations involved in the two procedures are presented, and are used to develop four user-friendly programs to estimate 3-phase vertical and horizontal separator dimensions. The VISUAL BASIC programming language in Microsoft Excel was used to develop the computer programs.
The program was validated using case studies from reviewed texts. Both procedures show similar results for all the case studies. The Arnold and Stewart design procedures involve less guesswork and is more suitable for conventional oilfield separator design. The results also show a decrease in separator height and length as separator diameter increased. This trend was observed in both design procedures.
In this paper, a new concept of ETLP has been proposed. It is composed of four square columns and a ring pontoon which is consisted of four box beams. The new platform has lesser blocks and welds compared to ETLP, so it can be built at a lower cost and in a shorter construction period. Meanwhile, the pontoon extensions in the new platform is part of pontoons, therefore, the fatigue problem in the welds at the root of extensions in ETLP is solved. A hydrodynamic analysis is conducted to prove the structure’s dynamically stabilities. The results showed the new design has a reasonable hydrodynamic characteristic.
Waterflooding can supply additional reservoir energy for producing substantial quantities of oil trapped due to limited displacement drive and poor sweep efficiency. However, water injection is not commonly used in the deepwater Gulf of Mexico (DW GoM) due to good primary recovery, drilling cost and facility limitations. In over 80 fields and 450 reservoirs, water injection program has been implemented in only 18 reservoirs in 13 fields, or less than 5% of potential waterflooding candidates.
DW GoM mid-Miocene reservoirs are characterized by sparse well counts, over-pressured, and generally good rock and fluid properties. Rock compaction and moderate aquifer influx often provide moderate to good natural drive energy and oil recovery. Primary oil recovery averages 32% with the 80% confidence range between 16% and 48%. However, Paleogene reservoirs are characterized by deeper depth, high pressure, high temperature, complex geology, and rock and fluid properties. Estimated recoverable oil is only 10% of OOIP assuming primary production and limited natural drive energy. Water injection programs will be difficult to execute in tight, abnormally-pressured Paleogene reservoirs. Waterflooding of deepwater turbidites has accumulated many lessons and learns now, and a comprehensive understanding of the influence of depositional environment and injection into over-pressured, highly compacting rocks is necessary. This paper is a detailed examination of Pleistocene-to-Upper Miocene age turbidite reservoirs in the DW GoM under water injection. Issues on waterflooding these deepwater plays were reviewed in the context of geological setting and depositional environment. Despite many drawbacks that tend to oppose the implementation of a waterflooding in Paleogene reservoirs, this paper still proves that they are candidates for water injection programs under the rules of good production practice. Moderate oil recovery is suggested in highly compacting reservoirs with supplemental injection drive. Overall, waterflooding strategies have proven to be highly effective in achieving good incremental oil recovery from the deepwater Gulf of Mexico reservoirs.