Hydrocarbon in place volumes are often inaccurate as a result of poor representation of the reservoir structure (by means of a 3D grid), that in combination with the use of traditional saturation calculation methods, lead to erroneous hydrocarbon volumes and poor investment decisions.
Traditionally a reservoir model is represented with a 3D grid, in a complex setting such as fault intersections and stacked reservoirs. A corner point grid is often used, which has limitations to represent this complexity. Further, the hydrocarbon saturations are then derived on a cell by cell basis on that 3D grid using simple averaging techniques of saturation height functions. The poor structure representation on the pillar grid in addition to the simplistic averaging methods lead to inaccuracies of the in place volumes especially where a prominent transition zone is present.
This paper presents new advanced saturation averaging methods (volume and height weighted) using saturation height functions on 3D grids. The new advanced saturation averaging methods are used on different reservoir models to compare the saturation distribution and volumetric differences against the traditional saturation calculation methods. A 4-way dip closure reservoir model with a tilted free water level (typical example of a carbonate reservoir in the Middle East), and a faulted S-grid model of the F3-FA field (North Sea) are used.
For the 4-way dip closure reservoir model, when comparing the advanced ‘volume weighted’ and traditional ‘by center of the part of the cell’ saturation averaging methods, a significant difference in the water saturations is observed which leads to about 5% difference in the calculation of in place hydrocarbon volumes. Further, it is observed that changing the thickness and orientation of the 3D grid cells can result in even larger differences of 5-10%.
The faulted F3 model shows that the difference between the hydrocarbon saturation values is largest where it matters most, that is, around the fluid contacts and in the transition zone. The new advanced saturation averaging methods give accurate hydrocarbon saturations irrespective of the size or complexity of the 3D grid and without any discretization effects.
Presence of H2S detected in producing wells of North Kuwait sweet waterflooded reservoirs over the last 18 years, gave indications of biogenic souring. In response to this, the Kuwait Oil Company engaged in detailed souring potential assessments of selected reservoirs such as the Raudhatain Mauddud (RAMA), to predict the further generation of H2S and define the required souring mitigation strategy to ensure safe production over the remaining field life.
The souring simulation modelling was conducted on the RAMA subsurface model with support from Shell, using a state of the art souring prediction program. The initial phase of the study consisted in the history match simulation to define the most likely souring mechanism in the field. The forecast considered various scenarios with a range of sensitivities on carbon nutrient and sulphate levels, both in formation and injected water in the field.
The history match simulation results showed a good correlation with most of the producers with available H2S data. The Forecast simulation over the next 15-year period predicts a moderate souring severity for this reservoir, based on the maximum H2S mass flow rate of 90 kg/d and H2S in gas maximum concentration of 85 ppmv at the field level.
This work provides the petroleum Industry further insights into the souring behavior when effluent water is injected in addition to seawater, particularly the effects of additional carbon nutrients fed into the reservoir.
Waterflood (WF) is the main drive mechanism of North Kuwait reservoirs. Different development strategies has been adopted to develop a giant carbonate reservoir in the asset. Irregular scheme of WF has been implemented in the last 5 years which made it challenging to properly evaluate the WF performance. This paper presents both numerical and analytical approaches to assess the current performance of the waterflood in this reservoir.
The first method uses actual production and injection data to generate traditional waterflood plots such WOR vs. Np, injection throughput, VRR and other diagnostics.
The second approach uses the numerical model to understand the fluid movements in terms of production and water injection. A high resolution model is used to know about the horizontal producers and injectors WF scheme. Streamline model tool is used to understand how the injectors impact their surrounding producers. Injector's efficiency, allocation factors and reservoir sweep efficiency are calculated using the simulation model.
Both approaches are compared to have a better evaluation of the waterflood.
When the waterflood started, a regular i-9 spot patterns was the way to develop the reservoir. The heterogeneity of the reservoir was observed clearly in the different performance of each pattern. Also, high permeability layer (thief zone) has adversely affected the reservoir performance during WF.
The sharp increase of water cut with very low corresponding recovery factor triggered a paradigm shift in developing this waterflooded reservoir. Injecting in lower layers and producing in upper layers (horizontal wells) was the next stage. This brought a great challenge to assess the performance of this WF scheme. Evaluating such a development strategy remains a achallenge.
This paper discusses the evolution of an Alkaline Surfactant Polymer (ASP) formulation for a challenging sandstone reservoir in North Kuwait. This is an on-shore reservoir, with no gas cap, featuring a moderately high residual oil saturation to waterflood of approximately 20-30%. Moreover, the reservoir has a light oil (API Gravity 30-35) with low Total Acid Number (TAN) and is undergoing a maturing waterflood – thus making it amenable to ASP implementation. However, the high reservoir temperature (90°C), in-situ brine salinity (>250,000 ppm) and divalent ion concentration (>20,000 ppm) place the reservoir at the upper threshold of ASP technology implementation.
In addition, the oil has a high emulsification tendency and was observed to form very stable brine-oil emulsions when sampled from the field. This was due to the high concentration of heavier components such as waxes, resins and asphaltenes, some of which are surface-active and tend to interfere with the action of synthetic surfactant at the oil-water interface making ASP formulation development for such oils very challenging. Furthermore, addition of polymer to improve the ASP/oil mobility ratio caused phase separation of the aqueous phase likely because the water-soluble polymer preferentially dissolves in brine while pushing out the hydrophobic surfactant. The methodology followed in this work was to select a surfactant with a high alkyl tail length to solubilize the heavier hydrocarbons in the oil, blend it with a more hydrophilic surfactant to increase the optimal salinity to match the target injection water salinity and overcome the surfactant phase separation issue when polymer was added to the formulation. The ASP formulation was successfully tested in the field in a Single Well Chemical Tracer Test (SWCTT) and was successful in reducing the remaining oil saturation from 0.24 ± 0.02 at the end of water flood to 0.06 ± 0.05 at the end of the chemical flood.
Estimating hydraulic frictional loss in narrow annuli is challenging, especially for deepwater offshore wells with extremely narrow drilling margins. The challenge arises from annuli that are formed by big bore packers like Gravel Pack Packers, where the annular clearance isextremely small. In cases where open hole completions are run with MPD (Managed Pressure Drilling), the well typically would be displaced to heavier weight fluids before the packer is set and MPD is isolated. This paper illustrates the complications and limitations for estimating friction loss due to the narrow annuli when using drilling hydraulic programs.
Accurate estimation of hydraulic friction loss is extremely essential when using MPD system to maintain BHP(bottomhole pressure) while drilling, tripping, cementing etc. While drilling, the hydraulic models would typically be calibrated to PWD (pressure while drilling) in the BHA (bottomhole assembly), but when running liners, casings or completion systems, the lack of PWD complicates hydraulics and friction loss estimations. This phenomenon is accentuated when displacing the well from lighter drilling fluids to heaviercompletion fluids,especially when the completion fluid reaches the narrow annuli and displays sudden increase in frictional loss value due to the hydraulic model limitations.
This paper focuses on the limitations of estimating the frictional loss in narrow annulus created by the Gravel Pack Packers,when predicted using the drillinghydraulicmodels, and proposes a solution for mitigating such anomalies in calculations. To assess the sudden changes in the pressure loss estimations, the paper further utilizes CFD (Computational Fluid Dynamics) and the frictional loss estimations in these narrow annuli. As an outcome of the study, the paper proposes unique solutions to estimate the frictional pressure loss due to narrow annuli.
This work investigates the results of the first deployment in the industry of technology Z on an offshore drilling rig with a heavy top drive. The study uses a quantitative analysis of downhole data to confirm the benefits of Z.
Z expands the stick-slip free operating envelope and does not require tuning. Following a dozen or so Z land rig deployments since 2015, the technology was added to a heavy offshore rig, a newbuilt, with modern hi-end variable frequency drives that enable near-zero control loop latencies. A study validates the effectiveness of the system with downhole rotary speed data.
The Z system was used for multiple sections in the Barents Sea, where the overburden traditionally causes troublesome torsional vibrations. The users of the technology gave a positive feedback from their first experiences. This work aims to verify qualitative surface observations with a quantitative analysis of downhole data. Downhole sensors captured the dynamics of multiple locations in the drill string over the course of about 3 weeks. Stick-slip severity was quantified using downhole rotary speed data. Periods when Z was turned on were compared to periods when Z was turned off.
Good quality downhole drilling data can provide valuable insights into the downhole environment, allowing for improvement of the drilling process. It can also greatly facilitate drilling automation. Despite these benefits, there are still high barriers to using downhole data in a timely and efficient manner. The work presented here aims to improve its usability for engineers and analysts by introducing a variety of strategies to automatically correct and draw insights from downhole measurements without human inputs.
Downhole dynamics measurements show errors that are currently inevitable, particularly because downhole sensors are affected by factors such as high pressures, high temperatures and a lack of appropriate calibration procedures. Methodologies for automatic corrections of such errors are presented and described in detail. All approaches are tested on medium to high frequency downhole data from a variety of field data sets.
Commonly observed sensor errors include drifts in accelerometer and strain gauge data. An algorithm described here corrects vibration data for offsets and enables a comparison of vibration levels throughout runs which otherwise would be impacted by such drifts. Strain gauge sensor drift affects weight/torque on bit measurements, which are generally corrected manually. The algorithms proposed here make better corrections than manual procedures by finding the exact instance of neutrality. This can potentially make time-consuming taring procedures in rig operations obsolete. Time alignment of downhole and surface data is another barrier for a comprehensive analysis and is often a source of many errors. Simple but effective methodologies are described that auto-align time-based data sets, even considering latencies due to travel times. In addition, novel data reduction techniques that help to effectively process, display, and analyze high-frequency data are also discussed.
Analysis of downhole data currently requires skills and experience that must be developed in a labor-intensive way from scratch in many organizations. This work summarizes practical experiences and novel scientific insights that can help any engineer to kick-start downhole data analysis. The paper aims to increase transparency and share ideas amongst the drilling community, with the goal of improving drilling performance through downhole data analysis.
Kharghoria, Arun (Kuwait Oil Company) | Garcia, Jose Gregorio (Kuwait Oil Company) | AlRasheedi, Khaled Saleh (Kuwait Oil Company) | Al-Rabah, Abdullah Abdul Karim (Kuwait Oil Company) | Sanwoolu, Ayodele Olusegun (Kuwait Oil Company) | Husain, Hisham (Shell)
This study presents an assessment of heterogeneity on vertical and areal scales and discusses the development of methodology for a proposed waterflood scheme in a heavy oil field in Northern Kuwait. The field produces average 15 API crude of 50-100 cp at 100 F. The field has a complex geologic and stratigraphic architecture, and the associated reservoirs are highly heterogeneous in nature. Both numerical simulation and analytical models were used to assess the performance of the proposed waterflood. Vertical and areal heterogeneity of the oil bearing formation were evaluated using Dykstra-Parsons coefficient, Lorenz coefficient and coefficient of variance methodologies. Both numerical simulation and analytical models were deployed to evaluate the waterflood performance under 5-spot and inverted 9-spot patterns for 20 and 10 acre spacing. An analytical excercise was carried out as a pre-check for the expected waterflood recovery factors. Results from all three methods of heterogeneity assessment indicated the existence of a highly heterogeneous reservoir with average Dykstra-Parsons coefficients being greater than 0.8. A heterogeneity distribution map shows strong presence of areal heterogeneity.
Al-Shammari, Asrar Ajaimi (Kuwait Oil Company) | Kharghoria, Arun (Kuwait Oil Company) | Garcia, Jose Gregorio (Kuwait Oil Company) | Saikia, Pabitra (Kuwait Oil Company) | Al-Shammari, Abdulrahman Fares (Kuwait Oil Company) | Al-Rabah, Abdullah Abdul Karim (Kuwait Oil Company) | Husain, Hisham (Shell) | Kalia, Devesh (Shell)
A comprehensive numerical and analytical assessment of water coning in a heavy oil field in Northern Kuwait is presented in this study. Several wells were investigated in light of possible coning affect. Based on the lessons learned from the field data and modeling efforts, a coning envelope is generated and possible mitigation actions are explored. The complex geologic and stratigraphic architecture of the reservoir with underlying oil-water contact presents a unique challenge to achieve water-free oil production in this field. The field produces average 150 API crude of 50-100 cp at 100° F.
Production data from wells from different structural locations were history-matched using numerical simulations on single well models (including type well models). Model runs were extended to estimate critical liquid rate to avoid coning. Additionally, critical rates assessed from several analytical models were compared against those from the numerical simulations.
Critical liquid production rates for different areas of the field have been assessed based on the coning envelope generated. Further works showed that the critical rate is also a strong function of operational, reservoir and fluid parameters as well as completions standoff from current oil-water contact (OWC). Since the current oil API is very close to that of water, the critical rate is not a strong function of the density difference of the reservoir fluids, however, difference in the fluid viscosities displayed a some degree of impact on the coning rate. Operational results also showed that average of 15 ft standoff from the existing OWC is critical to avoid imminent coning. This presents an important opportunity for efficient completion decisions of a candidate well. The most significant new finding is that two analytical models evaluated during this study indicated that these models have limited capability to assess the critical rate from the heavy oil reservoir, and appear to have high degree of sensitivity to oil viscosity.
This paper provides an integrated approach to assess and manage water cone in a heavy oil recovery project. Generated coning envelope provides a tool for a proactive strategy for rate management including opportunities for strategic well completion decisions. Another noteworthy assessment is that the existing analytical models have significantly limited capability to model water coning behavior in a heavy oil reservoir.
The cost per barrel is higher for Heavy Oil developments, and particularly thermal developments than for Conventional. Specific attention needs to be paid to the cost of Heavy Oil developments to ensure economic viability. The current cost basis for the heavy oil project shows that energy costs constitute some 45% of Unit Technical Cost and more than 65% of the OPEX per barrel. An OPEX cost improvement plan has been conceptualized to reduce the cost per barrel. Hence, the improvement plan focusses on Alternative Energy sources for steam generation.
In addition to the cost optimization, those initiatives will contribute heavily in achieving HH the Emir of Kuwait vision to cover 15% of Kuwait’s peak load with renewable energy by 2030". Based on current field development plans a feasibility study was carried out to determine the maximum practical and economic fraction of energy that can be contributed by renewables in heavy oil development. The bulk of the work was executed developing a model to study the supply-demand balance, as well as the gas prices ranges within the alternative energy solutions are viable.
To optimize the fuel gas consumptions two options were studied by utilizing the alternative energy solutions (solar steam and cogenerations) to generate steam instead of conventional boilers. On the power optimization side the study focused on the solar photovoltaic and wind energy. The lowest cost solution is to use direct solar steam and allow the steam injection at a variable rate - this may require some upgrades to allow fully- automatic flow control throughout the steam distribution system. With this method (and a typical weather year) solar fractions of approximately up to 40% may be possible. It may be possible to increase this further if the requirements for minimum steam flow in the steam distribution network can be reduced. With the use of thermal storage, the solar fraction can be increased to approximately 60-80%, however steam from storage is likely to cost significantly more than direct steam, especially as direct molten-salt coupled with oilfield- quality water has not yet been proven commercially.
As renewable power alone will not be able to meet the full demand of Heavy Oil field development, hence the utilization of cogeneration will be a feasible solution in order to supply the required steam demands in addition to solar and also to supply the required power in addition to solar PV. The redundant power generated by the cogeneration may be supplied to the Electrical Grid. The economics analysis illustrates that all renewable options considered have positive NPV. The economics for both PV and wind are robust, where maximum deployment is advised, subject to grid connection constraints. For solar steam, the economics are partially affected by the once-through steam generators (OTSG) CAPEX already spent, but still show positive NPV. Anticipated costs reductions for solar steam technology as a consequence of greater deployment of the technology over the next few years could further improve the NPV. Including the cogeneration, solar steam and less conventional steam generators in the future projects will maximize the NPV of the heavy oil.