Reservoir Souring Prediction in Deepwater Reservoirs for Field Development Planning

2021 ◽  
Author(s):  
Mohd Azri Hanifah ◽  
Sai Ravindra Panuganti ◽  
Nur Atiqah Zakaria ◽  
Nur Hazrina Kamarul Zaman ◽  
Raj Deo Tewari
Keyword(s):  
Hydrogen Sulfide ◽  
Volatile Fatty Acids ◽  
Produced Water ◽  
Water Injection ◽  
Development Planning ◽  
Development Plan ◽  
Monod Kinetics ◽  
Field Development ◽  
Huge Impact ◽  
Water Field

Abstract A deep-water Field X with two major Reservoirs U and L discovered recently offshore Malaysia is on development for early production. The subsurface plan for the Field X includes water injection. But the presence of sulphate rich seawater can provide a favorable environment for souring activity to take place. This study evaluates the reservoir souring potential for the green Field X as a result of seawater flooding. Reservoir souring is the increase of the hydrogen sulfide (H2S) concentration in produced reservoir fluids. As hydrogen sulfide is a highly toxic and corrosive gas, the production of H2S has a huge impact on the safety, infrastructure and facilities of the field. Whether a reservoir is susceptible to souring is dependent on a variety of factors. Some of these include water injection flow rate, temperature of the reservoir, presence of bacterial nutrients and rock minerology. Effective prediction of biogenic reservoir souring using computer models is essential when undertaking major technical and economic decisions regarding field development. For H2S concentration calculation PETRONAS utilized in-house stand-alone modeling tool that considers physicochemical hydrodynamics of multiphase flow, heat transfer, substrate propagation and bacterial activity. The simulator looks at bacterial growth both in planktonic and sessile forms. Monod kinetics is applied for the growth of bacteria, leading to the consumption of sulphate and volatile fatty acids which in-turn is linked to H2S generation. Along with H2S propagation, H2S scavenging by rock and H2S partitioning between the various phases is also accounted for. The model can also deal with the effects of lift gas, reinjection of sour produced water, injection of biocide and nitrite. Since the Field X is a green field and historical production data is unavailable, the model is calibrated against the provided field development plan (FDP) data with sensitivity analysis. The simulation runs show that the H2S breakthrough occurs before the end of production. The amount of H2S produced indicates that the risk of reservoir souring associated with seawater injection in U and L Reservoirs of the Field X is high. It is recommended to evaluate different reservoir souring preventive measures in combination with mitigative options in terms of chance of success, risks, and cost (CAPEX/OPEX) in the context of the Field X development plan.

DEVELOPMENT PLANNING FOR THE COSSACK AND WANAEA FIELDS

1994 ◽  
Vol 34 (1) ◽  
pp. 92
Author(s):  
G. B. Salter ◽  
W. P. Kerckhoff
Keyword(s):  
Cost Reduction ◽  
Water Injection ◽  
Development Planning ◽  
Oil Field ◽  
Oil Fields ◽  
Oil Reservoirs ◽  
Field Development ◽  
Oil Reserves ◽  
Oil Field Development ◽  
Significant Effort

Development of the Cossack and Wanaea oil fields is in progress with first oil scheduled for late 1995. Wanaea oil reserves are estimated in the order of 32 x 106m3 (200 MMstb) making this the largest oil field development currently underway in Australia.Development planning for these fields posed a unique set of challenges.Key subsurface uncertainties are the requirement for water injection (Wanaea only) and well numbers. Strategies for managing these uncertainties were studied and appropriate flexibility built-in to planned facilities.Alternative facility concepts including steel/concrete platforms and floating options were studied-the concept selected comprises subsea wells tied-back to production/storage/export facilities on an FPSO located over Wanaea.In view of the high proportion of costs associated with the subsea components, significant effort was focussed on flowline optimisation, simplification and cost reduction. These actions have led to potential major economic benefits.Gas utilisation options included reinjection into the oil reservoirs, export for re-injection into North Rankin or export to shore. The latter requires the installation of an LPG plant onshore and was selected as the simplest, safest and the most economically attractive method.

Incorporating Uncertainties in Well-Count Optimization With Experimental Design for the Deepwater Agbami Field

2005 ◽  
Vol 8 (06) ◽  
pp. 548-560 ◽  
Author(s):  
Gene M. Narahara ◽  
John J. Spokes ◽  
David D. Brennan ◽  
Gregor Maxwell ◽  
Michael S. Bast
Keyword(s):  
Experimental Design ◽  
Development Process ◽  
Gas Injection ◽  
Water Injection ◽  
Development Plan ◽  
Field Development ◽  
Wide Range ◽  
Geologic Model ◽  
Reservoir Description ◽  
Phase Phase

Summary This paper describes a methodology for incorporating uncertainties in the optimization of well count for the deepwater Agbami field development. The lack of substantial reservoir-description data is common in many deepwater discoveries. Therefore, the development plan must be optimized and proven to berobust for a wide range of uncertainties. In the Agbami project, the design of experiments, or experimental design (ED) technique, was incorporated to optimize the well count across a wide range of subsurface uncertainties. The lack of substantial reservoir-description data is common for many deepwater discoveries. In the Agbami project, the uncertainty in oil in place was significant (greater than a factor of 2). This uncertainty was captured in a range of earth (geologic) models. Additional uncertainty variables, including permeability, fault seals, and injection conformance, were studied concurrently. Multiple well-count development plans (high, mid, and low) were developed and used as a variable in ED. The ED technique allowed multiple well counts to be tested quickly against multiple geologic models. With the net present value (NPV) calculated for each case, not only was the well count for the overall highest NPV determined, but discrete testing of each geologic model determined the optimum well count for each model. The process allowed for testing the robustness of any well count vs. any uncertainty (or set of uncertainties). A method was demonstrated quantifying the difference between perfect and imperfect knowledge of the reservoir description (geologic model) as it pertains to well locations. Introduction The Agbami structure is a northwest/southeast-trending four-way closure anticline and is located on the Niger delta front approximately 65 miles offshore Nigeria in the Gulf of Guinea (see the map in Fig. 1). The structure spans an area of 45,000 acres at spill point and is located in 4,800 ft of water. The Agbami No. 1 discovery well was drilled in late 1998. The appraisal program was completed in 2001 and included five wells and one sidetrack drilled on the structure, with each encountering oil pay. These five wells and a sidetrack penetrated an average of approximately 350 ft of oil. In this phase (Phase 3) of the development process, the key objectives are to construct a field-development plan and to obtain sanctioning. With drilling depths of up to 10,000 ft below mudline in 4,800 ft of water, well costs at Agbami will be at the high end of typical deepwater costs. Therefore, an important optimization parameter in the field development is the total well count. Agbami is typical of many deepwater developments in that the seismic is less than perfect and the appraisal well data are sparse relative to the area coverage. Therefore, subsurface uncertainty is high. In fact, the 5% probable oil in place is more than two times the oil in place at the 95% probability. As a result, the development process is challenged with determining the optimum well count for the field development across the wide range of subsurface uncertainty. Several key development decisions were determined in the previous phase(Phase 2) of the development process. These decisions were taken as givens in this study and are listed as follows:• The recommended pressure-maintenance scheme and gas-disposition strategy for the 17 million-year (MY) units is a combination of crestal gas injection with peripheral water injection.• The recommended pressure-maintenance scheme and gas-disposition strategy for the 14MY/16MY units is crestal gas injection only.• The facility design capacity recommendations are:- 250,000 stock-tank bbl per day (STB/D) oil.- 450,000 thousand cubic ft per day (Mcf/D) gas production.- 250,000 STB/D water production.- 450,000 STB/D liquid production.- 450,000 STB/D water injection.

Alternative Method of Assessing Optimum Number of Water Injection and Infill Wells in a Field Development Plan

2021 ◽  
Author(s):  
M. Fitri Ramli ◽  
M. Shahrul M. Long ◽  
Amol Nivrutti Pote ◽  
Khairul Azri Ishak
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Net Present Value ◽  
Water Injection ◽  
Numerical Approach ◽  
Development Plan ◽  
Alternative Methods ◽  
Optimum Number ◽  
Injection Wells ◽  
Field Development

Abstract This paper discusses the workflow and method of selecting optimum number of infill and injection wells based on incremental recovery. Normally, for infill wells study, a ‘creaming curve’ method is used to evaluate the optimum number of wells against incremental recovery from the field. However, in the case of determining number of infill wells together with water injection wells, a more comprehensive approach is needed. One needs to evaluate the pressure depletion rate from existing and infill wells together with the dynamic of the producer-injector pairings as well as the sweeping factor. The paper is based on infill and water injection development plan for a brown field in Sabah basin which located in Malaysia. To maintain operatability of the field in the future, several new infill and water injection wells options are evaluated for optimum field life oil production. Unlike infill or producer-only assessment, the same ‘creaming curve’ approach for combination of infill and water injection wells is less effective as large number of simulation runs are needed to sample the combination of these wells that generate optimum oil recovery. This has proven to be challenging especially when the models are large which is normally the case for brown fields and it requires extensive computational hours. In the first part, a modified approach bringing some pre-analytic assessment of producer-injector pairing is being used. The pairings are first ranked based on streamlines visualization, drainage tables and their respective contributions towards oil recovery. The ‘creaming curve’ is then built based on the highest contribution as well as the sequencing of the pairings. The second method mentioned in this paper is the numerical approach through multi-objective optimization using assisted history matching and uncertainty tool. With the help of optimizer, the number of simulation runs can be drastically reduced when only best combination of infills and injectors for each total number of wells are considered. Both alternative methods will be compared with the full computational runs, sampling every single combination of wells. Finally, the optimum number of wells with the combination of infill and water injection wells are analysed based on cumulative oil recovery against the Net Present Value (NPV). This case study therefore demonstrates how alternative methods can be used to resolve the optimum number of infill and water injection wells to avoid lengthy and very large numbers of simulation runs.

60 Years Field Performance Data-Driven Analytics to Generate Updated Waterflood Field Development Plan in a North Kuwait Giant Carbonate Reservoir

2021 ◽  
Author(s):  
Basel AL-Otaibi ◽  
Issa Abu Shiekah ◽  
Manish Kumar Jha ◽  
Gerbert de Bruijn ◽  
Peter Male ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Oil Production ◽  
Horizontal Wells ◽  
Carbonate Reservoir ◽  
Development Plan ◽  
Data Driven ◽  
Water Flooding ◽  
Field Development ◽  
The Impact

Abstract After 40 years of depletion drive, a mature, giant and multi-layer carbonate reservoir is developed through waterflooding. Oil production, sustained through infill drilling and new development patterns, is often associated with increasingly higher water production compared to earlier development phases. A field re-development plan has been established to alleviate the impact of reservoir heterogeneities on oil recovery, driven by the analysis of the historical performance of production and injection of a range of well types. The field is developed through historical opportunistic development concepts utilizing evolving technology trends. Therefore, the field has initially wide spacing vertical waterflooding patterns followed by horizontal wells, subjected to seawater or produced water injection, applying a range of wells placement or completion technologies and different water injection operating strategies. Systematic categorization, grouping and analyzing of a rich data set of wells performance have been complemented and integrated with insights from coarse full field and conceptual sector dynamic modeling activities. This workflow efficiently paved the way to optimize the field development aiming for increased oil recovery and cost saving opportunities. Integrated analysis of evolving historical development decisions revealed and ranked the primary subsurface and operational drivers behind the limited sweep efficiency and increased watercut. This helped mapping the impact of fundamental subsurface attributes from well placement, completion, or water injection strategies. Excellent vertical wells performance during the primary depletion and the early stage of water flooding was slowly outperformed by a more sustainable horizontal well production and injection strategy. This is consistent with a conceptual model in which the reservoir is dominated by extensive high conductive features that contributed in the early life of the field to good oil production before becoming the primary source of premature water breakthrough after a limited fraction of pore volume water was injected. The next level of analysis provided actual field evidence to support informed decisions to optimize the front runner horizontal wells development concept to cover wells length, orientation, vertical placement in the stratigraphy, spacing, pattern strategy and completion design. The findings enabled delivering updated field development plan covering the field life cycle to sustain and increase field oil production through adding ~ 200 additional wells and introducing more structured water flooding patterns in addition to establishing improved wells reservoir management practices. This integrated study manifests the power, efficiency and value from data driven analysis to capture lessons learned from evolving wells and development concepts applied in a complex brown field over six decades. The workflow enabled the delivery of an updated field development plan and production forecasts within a year through utilizing data analytics to compensate for the recognized limitations of subsurface models in addition to providing input to steer the more time-consuming modeling activities.

Oil Reserves Evaluation and Field Development plan of Hakim Oil Field in Libya

2016 ◽  
Vol 18 (1) ◽  
pp. 39-53
Author(s):  
Omar Salih ◽  
Mahmoud Tantawy ◽  
Sayed Elayouty ◽  
Atef Abd Hady
Keyword(s):  
Oil Field ◽  
Development Plan ◽  
Field Development ◽  
Oil Reserves

Colonial development by intersector labour transfer, 1950–69

2017 ◽  
Author(s):  
John Toye
Keyword(s):  
Economic Development ◽  
Development Planning ◽  
Development Plan ◽  
Successful Development ◽  
Kwame Nkrumah ◽  
The Bible ◽  
British Colonial ◽  
Rapid Industrialization

As the colonization approach, metropolitan power tried to legitimize their rule by claiming that they aim at economic development. Arthur Lewis criticized the British colonial development plan for lacking comprehensiveness and, in the 1940s, laid out his own manifesto for rapid industrialization. Later, in Manchester University, he wrote the significant 1951 UN report on development and his famous article on development by intersector labour transfer. His controversy with Herbert Frankel did not satisfy the critiques, but became the bible for those who identify development with industrialization. Lewis’s time as a policy advisor to Ghana Kwame Nkrumah left him doubtful about the possibility of successful development planning and he effectively withdrew from the development scene, despite retaining Enlightenment values.

scholarly journals Incremental and acceleration production estimation and their effect on optimization of well infill locations in tight gas reservoirs

2021 ◽  
Author(s):  
Atheer Dheyauldeen ◽  
Omar Al-Fatlawi ◽  
Md Mofazzal Hossain
Keyword(s):  
Transient Flow ◽  
Development Planning ◽  
Main Role ◽  
Gas Reservoirs ◽  
Type Curves ◽  
Field Development ◽  
Drilling Performance ◽  
Well Location ◽  
Infill Drilling ◽  
Tight Formations

AbstractThe main role of infill drilling is either adding incremental reserves to the already existing one by intersecting newly undrained (virgin) regions or accelerating the production from currently depleted areas. Accelerating reserves from increasing drainage in tight formations can be beneficial considering the time value of money and the cost of additional wells. However, the maximum benefit can be realized when infill wells produce mostly incremental recoveries (recoveries from virgin formations). Therefore, the prediction of incremental and accelerated recovery is crucial in field development planning as it helps in the optimization of infill wells with the assurance of long-term economic sustainability of the project. Several approaches are presented in literatures to determine incremental and acceleration recovery and areas for infill drilling. However, the majority of these methods require huge and expensive data; and very time-consuming simulation studies. In this study, two qualitative techniques are proposed for the estimation of incremental and accelerated recovery based upon readily available production data. In the first technique, acceleration and incremental recovery, and thus infill drilling, are predicted from the trend of the cumulative production (Gp) versus square root time function. This approach is more applicable for tight formations considering the long period of transient linear flow. The second technique is based on multi-well Blasingame type curves analysis. This technique appears to best be applied when the production of parent wells reaches the boundary dominated flow (BDF) region before the production start of the successive infill wells. These techniques are important in field development planning as the flow regimes in tight formations change gradually from transient flow (early times) to BDF (late times) as the production continues. Despite different approaches/methods, the field case studies demonstrate that the accurate framework for strategic well planning including prediction of optimum well location is very critical, especially for the realization of the commercial benefit (i.e., increasing and accelerating of reserve or assets) from infilled drilling campaign. Also, the proposed framework and findings of this study provide new insight into infilled drilling campaigns including the importance of better evaluation of infill drilling performance in tight formations, which eventually assist on informed decisions process regarding future development plans.

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