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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 165587, "Reassessment of Multiphase Pumps in Field-Case Studies for Marginal Deepwater Field Developments," by N. Abili, F. Kara, and I.J. Ohanyere, Cranfield University. This paper was peer reviewed and published in the February 2014 SPE Oil & Gas Facilities magazine, p. 56.
This paper focuses on the applicability of subsea-processing technology (SPT) using multiphase pumps (MPPs) to develop marginal fields commercially. A technology selection consisted of a comparison of performances of several SPTs for effective development of marginal fields and was evaluated further with an analytical hierarchical process, resulting in the most effective innovative SPT for marginal-field development. The findings of this process were validated further in their applications to real fields, reflected in specific field-case simulation studies.
Most of the world’s exploration-and-production companies have a significant number of unconventional and remote fields in their portfolios. Recent industrial effort has been focused on the accelerated development of SPT. One of the innovative solutions is the handling and treatment of produced oil and gas at or below the seabed for transport to topside facilities, to mitigate flow-assurance issues.
Some of the notable benefits of subsea processing include mitigation of hydrate formation and management of pressure-related issues resulting from the production of heavy oil, increase in wellhead pressure, and increased hydrocarbon production from fields with low pressure profiles. In ultradeepwater and deepwater fields, subsea processing is the most effective solution because such fields are beyond human intervention (divers), and it is used to boost hydrocarbon production from green fields or brownfields, reducing production cost and the need for topside processing.
This paper explores subsea processing in the development of offshore fields. From the concept selection, an optimal or near-optimal solution of SPT was then applied to an offshore-field development. The application of the optimal solution is simulated with a transient-multiphase-flow dynamic-model program, and the production profiles obtained from the simulation are compared with the reservoir’s production profile. The present paper considers results presented on subsea MPPs as a possible solution to develop marginal offshore fields commercially.
Results and Analysis of Field-Case Study
The simulation covers an 8-year production period simulated over two isolated cases (see the complete paper for discussions of four such cases) with varying water cuts and productivity index (PI). This simulation compared the most-innovative and -effective SPT found through analysis, which is multiphase pumping. The base case is modeled in a transient-multiphase-flow program without any form of subsea processing or gas or water injection. Field A is a typical example, and the current production profile uses an electrical submersible pump (ESP) to boost production; however, this is not modeled here because of the difficulty in handling free gas at suction conditions, because this reduces the efficiency of the pump and creates difficulty in modeling an advanced gas handler or gas separator for an ESP in the transient-multiphase-flow program.
Hence, for each of the cases in the 8-year period, we ran concurrent simulations for different field-development profiles. The field-development profiles were simulated for two production cases:
Field A. The field is located in the North Sea, at a water depth of more than 180 m and a seabed temperature of 4°C. A 26 000-m length of pipeline at an uneven seabed is expected to create slugs in the flowline. The well that was considered was a deviated well with a vertical depth of 1848 m from the seabed and a horizontal distance of 800 m from the wellhead. This is a high-pressure field, with reservoir pressure in excess of 200 bar and temperature in excess of 70°C. Production is through water injection, tied back to a floating production, storage, and offloading vessel.Field B is discussed in detail in the complete paper. Two field-case studies from Field A will be outlined here; please see the complete paper for the results of two field-case studies from Field B.
Subsea-processing technology (SPT) is one of the frontier tools currently being explored by the oil and gas industry to open new opportunities and achieve more-effective exploitation of offshore oil and gas reserves. Exploration and production has moved into unlocking reserves that are less attractive and in difficult environments (e.g., marginal deepwater fields). These marginal fields are located remotely offshore and require one form of processing or another before they can be productive commercially. This paper focuses on the applicability of SPT employing multiphase pumps (MPPs) to develop marginal fields commercially. This was a result of the technology selection established by a comparison of performances of several SPTs for effective development of marginal fields using tools [e.g., quality function deployment (QFD)], and evaluated further using an analytical hierarchal process (AHP), resulting in the most effective innovative SPT for marginal-field development. The result from these tools was validated further in their applications to real-life fields, and this is achieved by specific field-case simulation studies using the OLGA transient multiphase flow dynamic model program to comercially develop marginal fields.
Abstract Objective/Scope International and National oil companies have in their portfolios deep offshore marginal fields. Development of these fields is usually constrained by the CAPEX, OPEX, flow assurance and safety issues, which increases with maturity of the field. Subsea processing technology (SPT) is not only pivotal for unlocking such fields, but offers a novel approach that meets the challenges of developing offshore marginal fields. The present paper explores conceptual development from some of the most innovative solutions and performance analysis of the optimal SPT with field case studies demonstrated. Methods, Procedures, Process The paper provides a reassessment of the different SPTs available in the market as well as the limitations of such technologies. Conceptual development is carried out using a 3-step approach involving the Quality function deployment (QFD) and its tools, the Voice of customer (VOC) and Quality Matrix or House of Quality (HOQ) that analyzes and compares the capabilities of various SPTs to overcome the techno-economic challenges of marginal fields. Revalidation of results from the QFD process is done using Analytical Hierarchal process (AHP) and its pair wise comparison process, leading to the optimal innovative SPT for marginal field development. Field case analysis of this novel solution is applied to fields in the North Sea and Gulf of Guinea over an eight years period. Results, Observations, and Conclusions The present paper validates the effectiveness of SPT in tackling marginal field techno-economic challenges such as large CAPEX and OPEX, slugging, low recovery rate, remoteness of location amongst others issues. Its application in one of the fields led to increased projected revenue of up to $450,000,000 in recovery, as well as significant reduction in maintenance and work over costs. The analysis shows that SPT such as the deployment of Multiphase Pumps can be a game changer if effectively applied in marginal field development. Novel/Additive Information The paper explores the novel application of QFD and AHP to develop offshore marginal fields. These tools have been used effectively in so many fortune 500 companies, where they have led to a significant reduction in cost as well as reduction in project implementation time. Proper application of the processes described in the present paper can serve as a better alternative over the traditional field conceptual development, to maximize recovery in offshore marginal fields.
Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Introduction The challenges associated with multiphase flow are as old as the oil business itself. The natural flow from most wells consists of some mixture of oil, gas, and water. Historically, separators were placed as close to the wellhead as possible to avoid problems associated with multiphase-flow behavior. However, as production has moved into more hostile environments and project and operating philosophies have changed, use of multiphase transport in oil and gas production operations has increased. For example, in the production scenario in Fig. 1, all production (gas, condensate, and water) from the subsea wells and the wellhead platforms is transported commingled to the central platform. At the central platform, liquid/gas separation is performed so that the gas can be compressed and the liquid pumped. The fluids (liquid and compressed gas) are then remixed and transported as a multiphase mixture in a single pipeline to shore. Onshore, the fluids are separated to sales specification. In this scheme, methanol may be needed at the wellhead to prevent formation of hydrates. The methanol is removed from the water phase onshore and sent back offshore for reuse. If methanol is not required in the infield network, the water can be separated on the central platform and disposed of offshore. To make production scenarios like this one both feasible and reliable, transient-multiphase-flow modeling is used in many different ways. This paper provides brief descriptions of these techniques that are based on our experience with more than 200 individual studies of multiphase pipelines and related facilities worldwide. These applications include conventional offshore, deepwater, arctic, and desert production and transportation systems. Line Sizing Selecting the line size for a single-phase pipeline is relatively direct. The greatest anticipated flow rate should be established, the available pressure driving force should be determined, and pressure-drop relationships should be used to select a line size large enough to transport the required flow. Typically, economics may drive the line size to still greater values to accommodate future production or third-party fluids. The line-sizing problem in multiphase flow is more problematic because bigger is not necessarily better. Fig. 2, which shows the envelope of operability, explains this concept. The envelope has three main curves. The snake-like curve shows how production is expected to change with water cut (as the field matures and additional wells are brought on line). These production numbers reflect total liquid flow rates. The upper curve establishes the throughput limit of the pipeline on the basis of pressure-drop constraints, as governed by expected flowing wellhead pressures. The region below the lower curve establishes the production and water-cut combinations where terrains lugging occurs. The region between the curves is the envelope of operability. In this case, production over most of the field life is inside the envelope. Increasing the line size moves the envelope up, and decreasing the line size moves it down. In this way, operational impacts of different line sizes can be assessed. The key to making the envelope of operability a reliable design tool is to use an accurate dynamic model to calculate the boundaries. In preliminary engineering, a design engineer often uses steady-state simulators (or other correlations based on low-pressure, small-diameter, air/water laboratory data).These relationships should be used with caution. In one case that ween countered while working on a subsea pipeline, transient-model predictions for the pipeline pressure drops were 30% greater than the steady-state-model predictions (with similar differences in predicted liquid holdups). On the basis of the transient-model results, the line size was reduced by 2 in. from the size initially recommended on the basis of steady-state-model results. Field data subsequently confirmed that the transient-model predictions were within 8% of the actual values. If the larger line size had been installed, the pipeline would have been in the terrain-slugging region under normal flowing conditions, creating substantial operational problems. Line Pack/Unpack Gas is difficult to store in large quantities unless converted to liquefied products. Therefore, offshore gas production typically is regulated to match onshore demand. Because of the storage (compressibility) and resistive properties (friction loss) of the pipeline, a time lag occurs between changes in the gas flow rate into the pipeline and corresponding changes in the gas flow rate out of the pipeline. To maintain deliveries during short offshore shutdowns, the pipeline may be operated in a packed condition. "Packed" in this sense refers to the additional gas that can be stored in the pipeline by increasing operating pressures. These operating pressures are higher than the driving force required simply to transport the gas to shore given the minimum allowable arrival pressure. Moreover, an oversized line has been used in some cases to provide the line packing necessary to ensure uninterrupted onshore delivery during temporary offshore shutdowns. In multiphase systems, this issue becomes more complicated because the liquid reduces the volume available for gas compression. Furthermore, increases in flow rate can produce the intended gas volumes but may also yield problematic quantities of liquid.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 149477, "Investigation of Liquid Loading in Tight Horizontal Gas Wells With a Transient-Multiphase-Flow Simulator," by Donald F.B. Jackson, SPE, SPT Group, and Claudio J.J. Virues, SPE, and David Sask, SPE, Encana, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed.
Liquid loading occurs in gas wells when production declines to a rate that is insufficient to lift the associated liquids to the surface. Liquid holdup in the horizontal section may impair production before liquid loading in the production tubing becomes evident. Holdup in the horizontal section can lead to slug flow at the tubing and to early onset of liquid loading in the tubing. The results from a transient-multiphase-flow model were found to be consistent with data acquired from video logging. Sensitivity analyses were performed with several normalized trajectories.
Technology applied in conventional reservoirs in offshore horizontal wells can be applied successfully in onshore horizontal wells in unconventional reservoirs. The Jean Marie formation is an Upper Devonian carbonate platform between two thick shale layers in the Greater Sierra area, approximately 90 km east of Fort Nelson, British Columbia, Canada. The formation has low porosity (averaging 6%), low water saturation (averaging 20%), and low permeability (less than 1 md to air). Formation depth ranges from 600 to 1500 m subsea—1000- to 1900-m true vertical depth. The formation is entirely gas saturated with a dry sweet gas (95% methane) and is variably underpressured, with initial reservoir pressures of 6 to 15 MPa.
The horizontal wells are drilled underbalanced to limit formation damage. Fig. 1 shows a typical well completion with 177.8-mm production casing set at the top of the Jean Marie formation. Gas is produced from the openhole portion of the completion. While drilling horizontally through the Jean Marie formation, the well trajectory is steered on the basis of gas-rate-while-drilling (RWD) data. The geologists maneuver up and down in inclination until a good permeability streak is indicated by a spike in flow rate from the RWD data. After reaching target depth, tubing (typically 60.3 mm) is installed and the well is brought on production. Typical gas- production rates for Jean Marie wells decline from an initial rate of 56×103 m3/d to 14×103 m3/d after 12 months and to 10×103 m3/d after 36 months.