Alusta, Gamal Abdalla (Heriot-Watt University) | Mackay, Eric James (Heriot-Watt University) | Collins, Ian Ralph (BP Exploration) | Fennema, Julian (Heriot-Watt University) | Armih, Khari (Heriot-Watt University)
This study has focused on the development of a method to test the economic viability of Enhanced Oil Recovery (EOR) versus infill well drilling where the challenge is to compare polymer flooding scenarios with infill well drilling scenarios, not just based on incremental recovery, but on Net Present Value as well.
In a previous publication (Alusta et al., 2011, SPE143300) the method was developed to address polymer flooding, but it can be modified to suit any other EOR methods. The method has been applied to a synthetic scenario with constant economic parameters, which has demonstrated the impact that oil price can have on the decision making process.
The method was then applied and tested (Alusta et al., 2012, SPE150454) with varied operational and economic parameters to investigate the impact in delaying the start of polymer flooding to identify whether it is better to start polymer flooding earlier or later in the life of the project. Consideration was also given to the optimum polymer concentration, and the impact that factors such as oil price and polymer cost have on this decision. Due to the large number of combined reservoir engineering and economic scenarios, Monte Carlo Simulation and advanced analysis of large data sets and the resulting probability distributions had to be developed.
In this paper the methodology is applied to an offshore field where the choice has already been made to drill infill wells, but where we test the robustness of the method against a conventional decision making process for which there is historical data. We do this by performing calculations that compare the infill well scenario chosen with a range of polymer flooding scenarios that could have been selected instead, to identify whether or not the choice to drill infill wells was indeed the optimum choice from an economic perspective.
We conclude from all the reservoir simulations and subsequent economic calculations that the decision to drill infill wells was indeed the optimum choice from an economic perspective.
Both oil and gold are commodities with price in US Dollars, but they choose different path in trend figure. While gold has been showing great stability over the years, oil keeps changing in price level. Oil price movements have distorted measurement of economic variables measured in dollar values. In economical evaluation for oil and gas field development projects longer than one year, oil price is one of the most critical assumptions.
This paper is trying to solve whether:
• gold is more stable than US dollars or other currencies
• gold equivalency is more reliable way to project the future costs/price
• the gold-based oil price can be applied in current economical evaluation template for justification of approval process on field development plan
Considering crude oil prices are moving dynamically for last decade, this paper exercise the model to determine realistic oil price assumption by using more stable "currencies??, thus it can provide more reliable and accurate economical evaluation. It shows that gold-based inflation-adjusted crude-oil price is preferable indampening or mitigating:
• effect of dynamic oil price nature
• impact of inflation
• risks of paper-based currency fluctuation
• discount rate requirement
Using case study of Indonesian Production Sharing Contract (PSC) fiscal terms, gold-based oil price provides more simple economical evaluation, resulting real net cashflow of field development plan. The paper concludes by demonstrating using gold equivalency instead of paper-based currencies provides more consistent and reliable nominal revenue in both perspective of PSC Contractor and Government.
Wu, JinYong (Schlumberger) | Banerjee, Raj (Schlumberger) | Bolanos, Nelson (Schlumberger) | Alvi, Amanullah (Schlumberger) | Tilke, Peter Gerhard (Schlumberger - Doll Research) | Jilani, Syed Zeeshan (Schlumberger Oilfield UK Plc) | Bogush, Alexander (Schlumberger)
Assessing the waterflood, monitoring the fluids front, and enhancing sweep with the uncertainty of multiple geological realisations, data quality, and measurement presents an ongoing challenge. Defining sweet spots and optimal candidate well locations in a well-developed large field presents an additional challenge for reservoir management. A case study is presented that highlights the approach to this cycle of time-lapse monitoring, acquisition, analysis and planning in delivery of an optimal field development strategy using multi-constrained optimisation combined with fast semi-analytical and numerical simulators.
The multi-constrained optimiser is used in conjunction with different semi-analytical and simulation tools (streamlines, traditional simulators, and new high-powered simulation tools able to manage huge, multi-million-cell-field models) and rapidly predicts optimal well placement locations with inclusion of anti-collision in the presence of the reservoir uncertainties. The case study evaluates proposed field development strategies using the automated multivariable optimisation of well locations, trajectories, completion locations, and flow rates in the presence of existing wells and production history, geological parameters and reservoir engineering constraints, subsurface uncertainty, capex and opex costs, risk tolerance, and drilling sequence.
This optimisation is fast and allows for quick evaluation of multiple strategies to decipher an optimal development plan. Optimisers are a key technology facilitating simulation workflows, since there is no ‘one-approach-fits-all' when optimising oilfield development. Driven by different objective functions (net present value (NPV), return on investment (ROI), or production totals) the case study highlights the challenges, the best practices, and the advantages of an integrated approach in developing an optimal development plan for a brownfield.
Fan, Zifei (Petrochina Research Institute of Petroleum Exploration and Development) | Yang, Xuanyu (China University of Petroleum) | Xue, Xia (China National Oil and Gas Exploration and Development Corporation) | Xu, An Zhu (PetroChina E&P Co) | He, Ling (Petrochina Research Institute of Petroleum Exploration and Development) | Zhao, Lun (Petrochina Research Institute of Petroleum Exploration and Development) | Mu, Longxin (Petrochina Research Institute of Petroleum Exploration and Development)
The well patterns and pattern types of well placement issue in a productive formation is an important aspect of the effective field development. The problem solution is impossible on the intuitive level due to the reservoir inhomogeneity. At present the well pattern is accepted to be located basing on the famous criteria, specialist experience and hydrodynamical simulation on a reservoir model. The designer should analyze many field development variants with different well spacing during limited time interval. The adjustment of large-scale multiwell field-development projects is challenging because the number of adjustment variables and the size of the search space can become excessive. This difficulty can be circumvented by considering well patterns and then optimizing parameters associated with pattern type and geometry. In this paper, we introduce a new framework for accomplishing this type of adjustment for vertical two or three reservoirs.The development of vertical multiple reservoirs were usually by a separate well pattern for every reservoir, or through reservoir-by-reservoir from bottom to top by only one well pattern. A separate well pattern for every reservoir requires drilling many more wells and higher investment costs, while development through reservoir-by-reservoir from bottom to top by one well pattern made oil recovery rate and development efficiency very low and uneconomic. Consideration on fully developing every reservoir well efficiently, firstly, an inverted-nine well pattern was designed for every reservoir and the well space was L (L was defined as an optimal well space for respective reservoir) and the distance between adjacent well patterns was L. Secondly, all wells were drilled to the bottom of the lowest reservoir. Thirdly, when average water-cut of producers in every two well patterns was greater than 80%, the two well patterns interchanged reservoirs. Finally, when all reservoir interchange was completed, every reservoir was developed by the new equivalent infilled well pattern with well space of L. The adjustment strategy made the required number of drilling wells in the whole field can be reduced by 50% and achieved better development effect. This strategy was put into practice on North Buzachi oil field in Kazakhstan and average oil rate of single well was increased by 20%, oil recovery rate has an increment by 12 percent, the recovery factor was increased by 6.7%, economic profit is 1.8 times that of one separate well pattern for every reservoir, the effect was perfect. This work analyzed the performance of this new strategy of well pattern design and adjustment to effectively develop vertical multiple series of reservoirs and the methods to determine the reasonable time of two well patterns interchanging reservoirs through simulation study and current application effects.
Ali, Zaki (Schlumberger) | G. Bonilla, Juan Carlos (Schlumberger) | Zolotavin, Andrey (Kuwait Oil Company) | Al-Shammari, Reem Faraj (Kuwait Oil Company) | Robert, Herric (Schlumberger) | Saleem, Hussain A. (Kuwait Oil Company) | Farid, Ahmad (Schlumberger)
As oilfields mature and new fields come into operation, real time asset management of reserves is providing ongoing challenges to Kuwait Oil Company (KOC). Fewer engineers are managing more wells under increasingly tougher environmental conditions and compliance regulations. The combination of these factors has driven the need for KOC to make a step change in its approach to operations by incorporating digital field concepts to transform the way engineers are working. The result is the Kuwait Intelligent Digital Field initiative.
To enable KwIDF, new technologies were deployed in both mature and immature assets, creating issues in terms of interoperability and integration thereby increasing the strain on the legacy IT infrastructure. In addition, there was the requirement to isolate the SCADA industrial networks from the corporate business networks while automating traffic control with the various enterprise data systems. This ‘managed' separation complicated the delivery of productivity tools to employees and posed the greatest challenge to creating a transparent, seamless KwIDF infrastructure.
The KwIDF Jurassic project was particularly challenging since it had the most limited existing infrastructure, requiring the design and deployment of an entirely new architecture scattered over significant distances and business areas. This in turn created significant hurdles in terms of integration and compatibility with the remainder of KOC's proprietary systems and technologies. Specific efforts were required to allow KOC's network infrastructure to be capable of embracing such solutions and technologies with proper security measures in place.
Developing a network infrastructure to enable real time solutions for KwIDF Jurassic involved analyzing the specific business drivers of the asset to ensure that the capital investment not only delivered results, but did so within a secure environment. This paper presents the methodology employed by KOC's Corporate IT Group (CITG) to deliver the right network infrastructure, along with lessons learned, for enabling the Kuwait Intelligent Digital Field Jurassic project.
This paper describes the results of the feasibility study of an arcticoffshore platform concept sponsored by ConocoPhillips. This concept consists ofa Conical Piled Monopod (CPM) platform, shown in Figure 1, assisted by an IceWorthy Jack-up rig, Gemini, to drill development wells in Multi Year iceconditions as illustrated in Figures 2 and 3. The Gemini design is beingjointly developed by ConocoPhillips and Keppel Offshore and Marine TechnologyCentre Pte Ltd based in Houston. Gemini is equipped with two drill rigsthat can simultaneously or individually cantilever above the well slots locatedon the deck of the CPM. The key benefit of Gemini lies in extending thedrilling season from a few months during ice free season to several monthsbeyond the ice free period.
The study was carried out at Granherne Limited under ConocoPhillips'supervision between March 2010 and February 2011. A topsides operatingload of 5,000 tonnes was assumed, instead of 70,000 tonnes (or more)corresponding to a two drill rig stand alone drilling and production CPM. Thefeasibility of a stand alone drilling and production CPM was presented inanother paper at Icetech12 in September 2012.
The study concludes that a Gemini assisted CPM is feasible for iceconditions in the Canadian Beaufort Sea. The ice loads were calculated,in consultation with Ken Croasdale, a well known specialist in this discipline.Ice conditions assumed in this study were in accordance with ISO-19906, namely,12m thick level ice and a very rare 25m thick ice island event. No icemanagement was assumed. A Gemini assisted CPM offers a much lighter platformcompared to a standalone CPM or Gravity Based Structure.
ConocoPhillips has a patent pending on the CPM. ConocoPhillips andKeppel Offshore have patent(s) pending on the Ice Worthy Jack Up drilling rig,Gemini.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150079, "Managing Fields Using Intelligent Surveillance, Production Optimization, and Collaboration," by Frans G. Van den Berg, SPE, Andrew Mabian, SPE, Ronald Knoppe, Edwin Van Donkelaar, Frans Terlaan, and Valentin Koldunov, SPE, Shell, and Rufina Lameda, Science Applications International Corporation, prepared for the 2012 SPE Intelligent Energy International, Utrecht, The Netherlands, 27-29 March. The paper has not been peer reviewed.
Bashatah, Lafya (Abu Dhabi Marine Operating Co.) | Al-feky, Mohamed Helmy (Abu Dhabi Marine Operating Co.) | Draoui, Elyes (Abu Dhabi Marine Operating Co.) | Ghalem, Salim (Abu Dhabi Marine Operating Co.) | Alurkar, Kaustubh D. (PetroTel Inc) | Graves, Hunter (Petro Tel, Inc.) | Jayanti, Shekhar (PetroTel Inc) | Giordano, Ronald M. (PetroTel Inc) | Farouk, Magdy (Abu Dhabi Marine Operating Co.)
Streamline analysis coupled with finite-difference simulation provides a novel effective approach for an integrated reservoir management. The output from the existing compositional reservoir model was processed to generate streamlines from the finite-difference simulation. Reservoir management data, historical well performance data, calculations from streamline bundles, and novel performance diagnostics are integrated to optimize the field management and maximize oil recovery.
Simulation and field data are combined to give an integrated understanding of the reservoir leading to smart reservoir management. Powerful streamline analysis is being used to help optimize injection and increase recovery efficiency. Real field data and model data are being analyzed to identify the areas of upswept oil and opportunities to improve the reservoir performance. This new methodology workflow is implemented in a user-friendly and intuitive way, giving more time for analysis and integration then data management.
This new integration methodology is applied for the first in UAE to integrate Reservoir management data, historical well performance data, calculations from streamline bundles, and novel performance diagnostics. It is a unique well, reservoir and field management application that can assist to optimize field development and maximize hydrocarbon resource value. This new methodology is designed to visualize flow paths, compute allocation factors, assess pattern performance, and optimize injection based on injector-producer connections. It can be used to generate and analyze streamlines, quantify fluxes, and visualize the performance of a reservoir. It can help in identifying un-swept regions of oil, dead spots, and low pressure regions. An analysis of the historical data was conducted to understand the development history. Diagnostic analysis techniques were used to evaluate the water and gas flood and identify problems and opportunities. This work was accomplished in three phases:
1- First phase: incorporation of reservoir management data into the "Analytics project", this part of the study allows field, zones and sector performance analysis after loading of the following data:
Capitalizing on the UAE's wide experience in the field of land reclamation and artificial island technology, the Abu Dhabi oil and gas industry, represented by ADNOC group of companies, is currently deploying an array of islands across Abu Dhabi's Exclusive Economic Zone in the Arabian Gulf for applications such as new field development and the upgrade or expansion of storage and offloading facilities. With favorable water depths and environmental conditions, land reclamation is often a more economical option for the accommodation of offshore facilities than the construction of fixed steel jacket platforms. ADMA-OPCO is currently engaged in applying the technology to projects such as the Satah Al-Raaz Boot (SARB) field development, a 105,000-bpd development comprising 86 wells on two artificial islands. Simultaneously, ZADCO is making progress on expanding drilling from the Upper Zakum field by constructing four artificial islands (UZAI) to increase field production to 750,000 bpd by 2015. While cost and schedule optimization will be realized with the selection of the artificial island option for these mega projects, designers and contractors are facing the challenge of securing or fabricating building materials in huge amounts for the construction of both the land masses and shore protection structures. Creative solutions to procuring these materials are tabled and investigated. Innovative engineering designs are tried and tested both numerically and using physical model tests. The presence of a soft soil layer within the foundation strata of one of the Upper Zakum islands required special treatment to satisfy island performance criteria. Schedule constraints of construction and fulfilling ADNOC's strategic production objectives continue to be the driving forces behind the resolution of all challenges.
Meziani, Said (ADNOC E&P) | Ibrahem, Mohamed Sayed (Abu Dhabi Marine Operating Co.) | Al-Hossani, Khalil (ADMA-OPCO) | Matarid, Tarek Mohamed (Abu Dhabi Marine Operating Co.) | Al Badi, Bader Saif (ADNOC)
A green field offshore Abu Dhabi is planned to be developed with miscible crestal gas injection and peripheral water injection scheme. Close to 100 slanted and horizontal wells (single in dual/triple Reservoirs) will be drilled from 2 artificial islands targeting four Upper Jurassic carbonate Reservoirs. Risks appear in developing the field due to the uncertainties related to complex faults and fractures network, carbonate reservoirs heterogeneity, Tar Mat, sour fluid production, and high departure wells.
This paper illustrates full field development plan optimization studies that were conducted on a green field. The main objective of those studies was managing the reservoir uncertainties to enhance the full field development plans. 3D seismic, detailed sedimentological study, identified Reservoir rock types, Reservoir fluid characterization (Equations of state) and special core analysis (SCAL) using data collected from limited available wells were comprehensively evaluated and integrated to the input data of a 3D dynamic reservoir model.
In order to achieve the studies objectives, number of parameters were addressed and optimized during assess and select phases of the full field development plan. These parameters are miscible and/or immiscible Gas injection scheme, peripheral Water Injection, Gas Injection timing and balance (standalone field development), and well locations based on structural and sedimentological uncertainties.
Integration of static and dynamic data supported the development plan optimization to address the high uncertainty of the targeted Reservoirs. In addition, several sensitivity studies have been conducted for the reservoir uncertainty parameter ranges to understand their impact on the full field development plan.