The aim of this study is to determine to what extent the quality of a history matched model is a good predictor of future production. The background is the common assumption that the better a model matches the production data is the better it is for forecasting, or, at the very least, it leads to an improved estimate of the uncertainty in future production. We demonstrate that the validity of this assumption depends on the length of the history match period and that of the forecasting period. It also depends on how heterogeneous the reservoir is.
The correlation between the quality of history match and quality of forecast depends on various factors. For the same level of heterogeneity one of the strongest factors is the water breakthrough time for the base and compared cases.
Broadly if both the base and compared case have water breakthrough before the end of the history match period then the forecasts are reasonable. However, there appears to be a very rapid transition from a reasonably good history match leading to a good forecast to a moderately good history match leading to a very poor forecast. If water breakthrough has not occurred there is a very poor correlation between the quality of the history match and the quality of the forecast. So, the traditional belief that a good history matched model will also produce a good forecast is not always true.
The Bahrain Oil Field was the first oil discovery in the Gulf Region in 1932 and is now in a mature stage of development. Crestal gas injection in the oil bearing, under saturated, layered and heavily faulted carbonate Mauddud reservoir has continued to be the dominant drive mechanism since 1938. Thirty eight 40 acre 5-spot waterflood patterns were implemented from 2011 to 2012. These patterns were located in both the South East and North West part of the Mauddud reservoir with a maximum injection rate of 80,000 bbl/day. With less than 10% PV water injected as of December 2012, premature water breakthrough was observed in most of the producers. Rapid water breakthrough in Mauddud A (Ba) is attributed to presence of high permeability vugs and layers resulting in water cycling and poor sweep in the matrix leaving bypassed oil. Following recommendations from the 2013 partner Peer Assist, the South East and North West waterfloods have been converted from pattern to peripheral with downdip wells providing water injection. Peripheral re-alignment has arrested the production decline, reduced water cut and stabilized production.
Surveillance data such as bottomhole pressure data, production logs, reservoir saturation logs, temperature logs and tracer data form the basis of understanding waterflood performance. Additionally, an array of analytical tools were used for diagnosis and analysis. Amongst the diagnostic tools, the Y- function helped to understand water cycling and sweep; the modified-Hall plot assisted in understanding the high-permeability channel or lack thereof and the water-oil-ratio (WOR) provided the clue on fluid displacement. Additional plots such as the "X" plot, decline curve, Cobb plot, pore volume injected vs. recovery, Jordan plot, and Stagg's plot were generated to gain insight on the waterflood.
Based on the waterflood analysis, a field study was initiated in December 2016 by shutting more than 80% of water injection followed by complete shut-in in September 2017. The purpose was to reduce the water cut, improve production taking advantage of gravity drainage effect of gas injectors located up dip of waterflood areas. The implementation of water injection shut-in is still ongoing in the Bahrain Field and pressure/production performance is being closely monitored. Improved production performance is observed following water injection shut-in.
This study underscores the importance of modern analytical tools to diagnose and analyze waterflood performance. This understanding also paves the way for much improved learning to take appropriate actions and help devise long-term reservoir management strategy.
Kumar, Sarwesh (Chevron Corporation) | Wen, Xian-Huan (Chevron Corporation) | He, Jincong (Chevron Corporation) | Lin, Wenjuan (Chevron Corporation) | Yardumian, Hrant (Chevron Corporation) | Fahruri, Irvan (Chevron Corporation) | Zhang, Yanfen (Chevron Corporation) | Orribo, Jose M. (Chevron Corporation) | Ghomian, Yousef (Chevron Corporation) | Marchiano, Iryna Petrovska (Chevron Corporation) | Babafemi, Ayanbule (Chevron Corporation)
Reservoir simulation is a widely accepted tool for assessing the impact of uncertainties on upstream investment decisions. Currently, the most widely used workflow addressing these uncertainties is a traditional two-step approach: 1) geoscientists performing static uncertainty analysis with earth modeling parameters and selecting a few representative geological models (for example, low-mid-high); 2) reservoir simulation engineers conducting dynamic uncertainty analysis with dynamic parameters combined with the pre-selected geological models and performing history matching, forecasting, or optimization. In this workflow, all the geological uncertainties are lumped into one parameter (the grid) for use in the second step. This severely reduces the flexibility for considering a wider range of alternative static realizations, and thus may bias the history match and forecasts. We implemented an integrated workflow, called "big-loop" that unifies the two-step approach into a single step. This allows for simultaneous and explicit analysis of both types of uncertainties and improvement in reservoir management decision quality. It also allows for direct modification of earth model parameters to achieve a history match with geological consistency. Although the concept is not new to the industry, it is rare to find references of field applications of the "big-loop" workflow. We present the applications of this workflow to both green and brown reservoirs to demonstrate its value in improving accuracy and efficiency. In a Gulf of Mexico green field, the workflow is applied for uncertainty analysis of static parameters (for example sand channel width and salt body extension) and dynamic parameters (for example rock-fluid properties) for probabilistic Original Oil in Place (OOIP) assessment and production forecast. The workflow facilitates the design of uncertainty resolution, upside capture and downside mitigation plans. In an onshore fractured reservoir, the workflow is applied for simultaneous history matching using static fracture parameters (fracture length and aperture) and dynamic parameters. The workflow improves the model accuracy and decision quality for the upcoming IOR/EOR development project. In an offshore gas field, the workflow is used to perform experimental design (ED) studies with static and dynamic uncertainties. This systematic & automatic workflow eliminates manual inputs and reduces the need for recycles. Finally, in another field, the workflow is used to perform probabilistic history matching using static and dynamic parameters. This workflow is capable of delivering a full-cycle solution for uncertainty assessment and probabilistic history matching with high efficiency and high quality results.
Lin, Dong (Oil & Gas Technology Centre, DNV GL) | Zhang, Ding (Oil & Gas Technology Centre, DNV GL) | Cho, Chungun (Oil & Gas Technology Centre, DNV GL) | Wang, Andy (Oil & Gas Technology Centre, DNV GL) | Ruskin, Alex (DNV GL) | Qiu, Xiaohong (COSCO Shipping Co., Ltd.)
This paper outlines the methodology taken for the Meren Gas Gathering Compression Platform (GGCP) dynamic positioning (DP) assisted float-over. The feasibility assessment, DP time domain analysis, swell model used for DP float-over analysis and operational aspects for motion optimization have been outlined to demonstrate the innovative concept leading to the first safe and reliable DP float-over installation in West Africa. In addition, recommendations for further improvements on the present DP float-over state-of-the-art are made to account for the challenging environmental conditions of West Africa or other areas with swell-dominated seas.
Over the past 15 years, about twelve DP float-over topsides installations have been executed in various offshore locations in the world including the Middle East, Southeast Asia and South China Sea. The principal advantage of using DP is that less marine spread is needed, meaning a shorter required weather window and hence higher workability. As a result, DP floatovers can be more cost effective than a moored methodology, which is often the driving decision-making factor.
Prior to the installation of the Meren Gas Gathering Compression Platform (GGCP) topsides (approximately 7, 400MT) in the Meren and Sonam fields offshore Nigeria in December 2014, no attempt had been made at performing a DP-assisted float-over in West Africa. Conversely, there have been several successful moored float-overs in the West African region. This can be linked primarily to challenging operational environments, with prevailing long-period swells that may cause significant motion. COSCO’s Tai An Kou, a 20,000 MT DP heavy lift vessel was used for the GGCP topsides floatover installation. Technical and operational considerations and design optimizations were tailored to cope with the station-keeping and motion challenges posed by the West African environment.
This paper presents an overview of the methodology that was applied for the GGCP topsides DP-assisted float-over installation. The engineering methodology is presented, both for typical float-over elements and for the specific jacking system applied to achieve rapid load transfer of the topside weight to the jacket. In addition, the optimization methodology and results for more efficient and reliable workability assessment, DP capacity analysis and swell model analyses is presented. Finally, design choices surrounding equipment layouts for a safer mating operation are discussed, including an overview of the float-over operation key stages, and items that were included to cope with a swell-dominated environment.
Reservoir E is an offshore saturated black-oil reservoir with three lobes, initially thought of as independent reservoirs, but later seen as lobes of same reservoir with acquisition of more pressure data. It started production in 1968, but was shut-in in 1985 due to declining pressure. After the onset of waterflood in 1992, pressure data showed the reservoir behaving like two pressure tanks aerially (Main and Horn Area). The main area showed good pressure response from water-flooding but limited response was observed in the horn area. The challenge has been how to improve the current reservoir performance given the availability of reserves especially in the horn area which is pressure challenged.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in San Antonio, Texas, USA, 8-10 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.
Kaleta, Malgorzata (Shell Global Solutions International BV) | Van Essen, Gijs (Shell International E & P) | Van Doren, Jorn (Shell) | Bennett, Richard (Shell International Exploration and Production Co.) | van Beest, B.W.H. (Shell) | van den Hoek, Paul (Shell) | Brint, John Forsyth (Shell Exploration & Production) | Woodhead, Timothy Jonathan (Shell International Ltd.)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the EAGE Annual Conference & Exhibition incorporating SPE Europec held in Copenhagen, Denmark, 4-7 June 2012. The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. Abstract In the petroleum industry, history-matched reservoir models are used to aid the field development decision-making process. Traditionally, models have been history-matched by reservoir engineers in the dynamic domain only. Ideally, if any changes are required to static parameters as result of history matching the dynamic model, then these should be reflected directly in the static reservoir model, ensuring consistency between the static and dynamic domain. In addition, static model uncertainties are often not evaluated in the dynamic domain, which can result in the detailed modeling of geological features that have little impact on the dynamic behavior of the reservoir or the resulting development decision. This paper demonstrates a workflow where the reservoir simulator and static modeling package are closely linked to promote a more integrated approach to reservoir model construction, facilitating the interaction between subsurface disciplines. Using either the reservoir simulator or the static modeling package as the platform, the output of the workflow is a sensitivity analysis of the uncertainties related to structure, rock properties, fluids and rock-fluid interactions. The workflow is described for both a synthetic model and also a reservoir model from a real field case. The method presented here can significantly enhance the understanding of the impact of both static and dynamic subsurface uncertainties on development decisions.