The negative impacts of high water cut in mature fields are well known within the oil & gas industry. Water production preventive & mitigative measures are well established and documented: Wireline or coil tubing conveyed diagnostic and work-over operation(s) is one of such common preventive measures. This paper, through a series of integrated case studies will highlight the best practices for wireline conveyed logging and work-overs with one common goal, i.e. to achieve the water production to a minimum acceptable level in deviated high water cut wells.
The prolific XYZ field is located in the Northern North Sea and it produces oil from Jurassic Brent Group. Oil production from the XYZ reservoir started in early 1978, with 43 producing wells and 15 water injection wells targeting the Rannoch, Etive, Ness and Tarbert sands. Oil and gas production peaked in 1982 and since then production has steadily declined for this field. The increasing water cut in the wells of this field is presenting a challenge for the operating companies.
Production profiling using advanced Production Logging data, casing/tubing integrity check using Multi-Finger Caliper data and saturation monitoring using cased-hole Reservoir Saturation data was done in these wells to ascertain the water producing zones and do the subsequent well intervention, if required. A strategic diagnostic test was designed to precisely evaluate the flow profile using advance production logging tool consisting of 5 mini-spinners & 6 sets of each electrical and optical probes; Real-time data assessment and analysis was done for different flowing rate surveys to validate the findings. Additionally, casing condition was evaluated using Multi-Finger Caliper to decide Plug or Straddle setting depths. Also, new hydrocarbon bearing zones were identified based on cased-hole saturation tool results. The analysis results boosted the cumulative oil production.
This study demonstrates the importance of making real time interpretation decisions at the wellsite and the benefit of developing a good working relationship between wellsite engineers and onshore technical support. The results of this work led to the unequivocal determination of major oil and water producing zones in deviated high water cut (95%+) wellbores which further helped in taking workover decisions to carry out water shut off, utilizing either plug or straddle technology. The findings of caliper data determined the appropriate plug or straddle setting depths. The results were compared and confirmed with the nearby well dynamic pressures and production data.
The technical approach and processes applied to wells of XYZ field is a valuable example guide to decide water shut off zones and technique of similar plays. This study consists of three integrated case studies from a mature field where water shut-off zones and technologies were decided based on the findings of production logging and well integrity data. Also, re-perforation jobs were performed based on the cased-hole reservoir saturation data results. These strategic workover operations ultimately led to significant increase in hydrocarbon production.
Mahmoud (Mudi) Ibrahim and Gregor Hollmann, Wintershall Summary Brownfields in this paper are defined as mature fields where production declined to less than 35-40% of the plateau rate and where primary and secondary reserves have been largely depleted. Big data, high field complexity after a long production history, and slim economic margins are typical brownfield challenges. In the exploration-and-production (E&P) industry, "sequential" field-evaluation approaches (first "static," then "dynamic"), have proved successful for greenfield development, but often do not achieve satisfying results for brownfields. This paper presents a new work flow for brownfield reevaluation and rejuvenation. The "reversed" geo-dynamic field modeling (GDFM) rearranges existing elements of reservoir evaluation to obtain a purpose-driven, deterministic reservoir model, which can be quickly translated into development scenarios. The GDFM work flow is novel because (1) it turns upside down the discipline-driven sequential work flow (i.e., starts with the history match) and (2) it uses dynamic data as input to calibrate seismic (re-) interpretation that acts as a main integration step. It combines all available data already during horizon and fault mapping. Field diagnosis, flow-unit identification, well-test reanalysis, and petrophysical and geological interpretations are all combined in a cross-discipline interaction to guarantee data consistency. This directly ensures a fully integrated, "geo-dynamic" model that forms the basis for reservoir modeling.
The field has multiple reservoirs varying between carbonates, clean sand stone and shaly sand stone. Baharyia formation is the main producing reservoir in the field. In the latest years of the field life, an unrealistic recovery factor was reached making the volume of the recovered gas exceeds the maximum volume that could be recovered from this reservoir. Hence, a new further investigation and review for the previously calculated GIIP was initiated. The results of this study yielded that the main uncertainty in the volumetric calculations was the petrophysical evaluation subsequently a new unconventional petrophysical evaluation approach was performed.
Mahmoud (Mudi) Ibrahim and Gregor Hollmann, Wintershall Summary Brownfields in this paper are defined as mature fields where production declined to less than 35-40% of the plateau rate and where primary and secondary reserves have been largely depleted. Big data, high field complexity after a long production history, and slim economic margins are typical brownfield challenges. In the exploration-and-production (E&P) industry, "sequential" field-evaluation approaches (first "static," then "dynamic"), have proved successful for green field development, but often do not achieve satisfying results for brownfields. This paper presents a new work flow for brownfield reevaluation and rejuvenation. The "reversed" geo-dynamic field modeling (GDFM) rearranges existing elements of reservoir evaluation to obtain a purpose-driven, deterministic reservoir model, which can be quickly translated into development scenarios. The GDFM work flow is novel because (1) it turns upside down the discipline-driven sequential work flow (i.e., starts with the history match) and (2) it uses dynamic data as input to calibrate seismic (re-) interpretation that acts as a main integration step. It combines all available data already during horizon and fault mapping. Field diagnosis, flow-unit identification, well-test reanalysis, and petrophysical and geological interpretations are all combined in a cross-discipline interaction to guarantee data consistency. This directly ensures a fully integrated, "geo-dynamic" model that forms the basis for reservoir modeling.
George, C. O. (Department of Geological Sciences, Nnamdi Azikiwe University) | Thomas, S. W. (Chevron Nigeria Limited) | John, M. (Chevron Nigeria Limited) | Gani, A. (Chevron Nigeria Limited) | Emmanuel, A. K. (Department of Geological Sciences, Nnamdi Azikiwe University) | Norbert, A. E. (Department of Geological Sciences, Nnamdi Azikiwe University)
Post-drill pore pressure and fracture gradient analyses were carried out in an offshore hydrocarbon field, of Niger DeltaBasin, the G-field, using petrophysical logs, drilling parameters and pressure data. Four wells were analyzed and the results from the analysis will serve as a look back in building a Pre-Spud pore pressure and fracture gradient model for future drilling of exploration and production wells. The overburden gradient and normal compaction trend were generated based on an empirical formula. The pore pressure gradients were computed using the Eaton’s and Miller’s method respectively. Mud weights, drilling parameters and drilling events were used to calibrate the pore pressure gradients. Fracture gradient was computed using Mathews and Kelly’s method with pore pressure definitive, overburden gradient and effective stress ratio as the inputs. Based on the empirical methods, pressure transition zones were detected across the four wells with three (3) pressure ramps of magnitude of 1.23 ppg (Pound Per Gallon), 2.55ppg and 1.52ppg respectively. Pore pressure gradient model generated from the study revealed normally pressured zones at the shallower part of the unconfined section in all the wells within the range of 870 and 6273 feet TVD (True Vertical Depth) with an average shale pore pressure of 8.4ppg for Well 1,4715 and 9145 feet TVD with an average shale pore pressure of 8.5ppg for Well 2, 2614 and 7736 feet TVD with an average shale pore pressure of 8.39ppg for Well 3 and 4227 and 7972 feet TVD with an average shale pore pressure of 8.4ppg for Well 4. The top of the overpressured zones (>0.47 Psi/ft) (9ppg) were established across the four wells. The analysis of pore pressure of the field shows that the depth to the overpressured zones ranges from 7498 to 8859 feet TVD for Well 1,9825 and 13582 feet TVD for Well2, 7741 and 12264 TVD for Well 3 and 8307 and 12220 feet TVD for Well 4.
Etokakpan, Eteobong (Shell Petroleum Development Company) | Keme, Bomo (Shell Petroleum Development Company) | Nwonodi, Chike (Shell Petroleum Development Company) | Amogu, Daniel (Shell Petroleum Development Company) | Orekoya, Adedoyin (Shell Petroleum Development Company) | Longe, Victor (Shell Petroleum Development Company) | Olubamise, Taiwo (Shell Petroleum Development Company) | Ukauku, Ikwan (Shell Petroleum Development Company) | Nworie, Ejiuwa (Shell Petroleum Development Company)
Managing uncertainties during subsurface modelling in brown field re-development requires robust identification and quantification of impact of the underlying uncertainties. Within a given cycle of integrated reservoir modelling, a modelling strategy can only be defined based on associated uncertainties and development options. This paper focuses on using the Design of Experiment to screen and quantify the impact of uncertainties and evaluate development outcomes in a brown field.
The paper details steps taken to identify and quantify subsurface uncertainties in a multi stacked reservoirs that could impact development options. The overall development strategy was to: (a) Introduce artificial lift and offtake management to keep existing wells flowing, (b) Install gas lift supply lines from new gas-lift skid at the flowstation to existing wells requiring gas-lift, (c) drill and complete additional wells using existing locations, (d) hook up the new wells to existing remote manifold and route to flowstations via existing bulklines. To access the impact of uncertain parameters and its ranges of uncertainty were identified and quantified based on current understanding of the reservoirs. The Plackett-Burman Design of Experiment was used to screen each parameter using the Tornado and/or Pareto Plots. The key uncertainties (heavy hitters) identified from the screening stage were carried forward to develop a Response Surface Model (RSM) using Box-Behnken experimental design in order to sample the full uncertainty space associated with each reservoir. The probability distributions of In-Place and cumulative production were generated using Monte-Carlo analysis and estimate of the Proved, Probable and Possible volumes and ultimate recovery were obtained (part of methodology)
From the study results, the feasibility for further oil and gas development based on 3D reservoir simulation with several development scenarios and options were evaluated. Results of the deterministic possible outcomes were used to identify specific cases that closely matched the Proved, Probable and Possible volumes from the Monte-Carlo distribution. Model provides tool for better well and reservoir management.
As part of the corporate technology strategy Statoil has launched a technology plan for the Subsea Factory concept. The plan describes how to combine subsea production and processing technology elements with key business cases and define enabling and cost-efficient field development concepts.
With the advent of moving processing facilities from topside to subsea, Statoil has made major technological advances in placing conventional processing equipment on the seabed. As of today, Statoil has successfully deployed subsea pumps and subsea separators (Troll Pilot and Tordis). Statoil is also in the process of deploying the world's first subsea compressors in 2015 (at both the Åsgard- and Gullfaks field).
While there has been a gradual increase in the complexity of the subsea processing systems we have also advanced our analytical and modelling approach to subsea processing concept evaluation and selection. In our recent concept evaluation we have used an integrated modelling approach, in which subsea processing options are directly linked to reservoir models, flow lines and surface facilities. This enables us to see value added in terms of increased reservoir productivity, but also overview of entire system behavior from reservoir to the topside, throughout the expected field life.
The cost level within subsea has increased by a factor 2.5 over the last 10-12 years. Statoil aims at establishing a Business Agreed Standardization on subsea processing interfaces and modules.
This standardization strategy will allow suppliers to compete within modules/technology elements, but standardize on module size and open interfaces to achieve plug-and-play functionality
The goal is to reduce costs and improve competitiveness of subsea solutions:
More profitable subsea developments Increased subsea processing volume
More profitable subsea developments
Increased subsea processing volume
Statoil believes that alignment with the other operators is vital to succeed in establishing a global, open standard.
Standardization enabling cost reduction through simplification More profitable subsea developments Increased subsea processing volume (? win-win-solution for the O&G industry)
Standardization enabling cost reduction through simplification
More profitable subsea developments
Increased subsea processing volume (? win-win-solution for the O&G industry)
The paper describes the ongoing work to achieve standardization of the Brownfield Subsea Factory with focus on near infrastructure solutions of existing fields. Subsea boosting and compression are important technologies enabling extended lifetime and increased recovery of mature subsea fields. In the paper several business cases will be described.
There is little commonality of fiscal incentives in the oil and gas sector. This is demonstrated in the North Sea, where rapidly changing market fundamentals had led to a range of fiscal measures aiming to incentivize the sector. Until very recently, rising cost of development against the backdrop of a maturing basin made the North Sea a less attractive place to invest in. Renewed interest in the North Sea seen in the last 5 years has been a direct result of the UK and Norwegian governments engaging with the stakeholders and introducing new policies which have the right incentives to extend basin life. However, in the UKCS, some would argue that these changes have come too late and investment and production levels have been already damaged. A brief review of the challenges in each country, the impact of fiscal incentives and to what extent they have been successful will form the main part of this paper.
Seabed equipment is at times deployed to do work on, or add energy to, produced fluids to improve or ensure sustained flow when natural reservoir pressure declines. This hardware includes subsea pumps and compressors. The power required to create a meaningful impact on production with these systems is generally substantial, i.e. several thousand horsepower or more. The power supplied to a fluid is hydraulic and is accommodated through application of rotating machinery (subsea pumps/compressors). This machinery converts electric power into rotational power through an electric motor, which then turns the shaft of the pump/compressor to do the work. Electric power to the subsea equipment from the source is generally transmitted via subsea power cables operating at 50/60 Hz. However, as distance and power levels become ever greater, stable AC power transmission becomes challenging due to excessive reactive power demand within the transmission cables.
What follows is a discussion of the present and anticipated, future power demands associated with subsea pumping and compression systems and the technical issues associated with conventional long distance, high power AC transmission for these applications. Distribution system topology and technology limits will be discussed to address more complex subsea configurations. Furthermore, the focus of submarine cable applications will be limited to Subsea Tiebacks to streamline the subject matter and manage document length.
Finally, solutions (opportunities) are proposed to address the range of issues presented. Solutions include high voltage, low frequency power transmission and high voltage DC power transmission. Reference is also made to this year's Subsea Processing Poster, developed by INTECSEA and published by Offshore Magazine (March 2013). In particular, Graph 4 - Subsea Power Transmission is briefly described to reinforce the aforementioned subject matter and afford readers a fuller understanding of the range and depth of information embedded within the graphic.
Introduction: A Brief History of Submarine Cable Applications
Submarine power cables have been around for more than a century and their application has evolved over the years. Early in life, submarine power cables were used to supply isolated offshore facilities such as lighthouses, infirmary ships, etc. As submarine power cable technology evolved, cables were used to link shore-based power grids across bays, estuaries, rivers, straits .
Present Day Uses
Today, submarine cables are used in a variety of applications, including:
With growing reliance on offshore-based renewable energy schemes, many countries now class submarine power cables as critical infrastructure.
During the last 25 years Statoil, in cooperation with key vendors, have developed technical solutions for subsea field development resulting in more than 500 subsea wells.
As part of the corporate Technology strategy Statoil has launched a technology plan for the Statoil Subsea Factory™ concept. The plan describes how to combine subsea production and processing technology elements together with key business prioritised elements such as long distance multiphase transport, floating production facilities and pipeline networks to enable cost-effective field development. In addition, subsea production and processing can enable accelerated production and increased recovery in an energy-efficient manner, and with low environmental footprint
This paper provides an overview of the technologies enabling the Subsea Factory concept and the operating experience gained in assets having implemented subsea processing technologies.
The paper describes the technology staircase starting with subsea boosting in the LuFeng field and the separation, produced water reinjection and fluid boosting applications at Troll Pilot and the Tordis fields. The paper describes Tyrihans raw seawater injection and summarises the gas compression technology projects underway for the Gullfaks and Åsgard fields.
The plan takes account of two specific value-creation goals Statoil is targeting - namely to realise subsea compression by 2015 and a complete subsea factory by 2020.
Focus on establishing a Subsea Factory concept can be explained by the desire to improve the economic value of field developments. Utilizing a system approach from reservoir to export system, combine and reuse in new ways the subsea production and processing technologies already installed or being constructed in Statoil.
The processing element will enable the fluids to be treated to a level where they can be safely transported in flowlines to a downstream host, whether onshore or offshore, fixed or floating. Future generations of subsea factory may include more sophisticated processing elements.
Statoil's vision is to develop and deploy all the necessary technology elements required for a "subsea factory??, i.e. for the equivalent of a topsides processing facility to be operated on the seabed, enabling remote subsea to beach hydrocarbon transport solutions in any offshore location. Statoil will be "Taking subsea longer, deeper and colder?? to accelerate and increase production?? by implementing the Statoil Subsea Factory™. The term "Older?? is also discussed in light of the potential to reuseexisting technology elements to increase recovery and maintain production at existing/brownfield facilities at the Norwegian Continental shelf.