Arshad, Muhammad Waseem (Technical University of Denmark DTU, DTU Chemical Engineering, Center for Energy Resources Engineering, Søltofts Plads 229, DK-2800 Kongens Lyngby) | Loldrup Fosbøl, Philip (Technical University of Denmark DTU, DTU Chemical Engineering, Center for Energy Resources Engineering, Søltofts Plads 229, DK-2800 Kongens Lyngby) | Shapiro, Alexander (Technical University of Denmark DTU, DTU Chemical Engineering, Center for Energy Resources Engineering, Søltofts Plads 229, DK-2800 Kongens Lyngby) | Thomsen, Kaj (Technical University of Denmark DTU, DTU Chemical Engineering, Center for Energy Resources Engineering, Søltofts Plads 229, DK-2800 Kongens Lyngby)
Smart water flooding is an advanced method for enhanced oil recovery (EOR) in which the composition of injected brine is altered by varying the concentration of selected ions that can increase the oil recovery from various carbonate reservoirs. Besides wettability alteration mechanism, the formation of water-soluble oil emulsions has been reported as a possible reason to explain the observed increase in oil recovery using smart water. The formation of water-soluble oil emulsions takes place on the interaction of insoluble salts (fines) with oils. However, the interaction of these fines with the crude oil is not very well studied for carbonate reservoirs. This work presents emulsion formation in water-oil systems in the presence of water-insoluble fines. The effect of amount of fines on emulsion formation is also examined.
Synthetic seawater (SSW) and deionized water (DIW) were used as water phase, two model oils (decane (D) and 1:1 vol. ratio of hexane-hexadecane (HH) mixture) and North Sea crude oil (NSCO) were used as oil phase, and fines of CaCO3 (≤ 30 µm) and CaSO4 (≈ 44 µm) were used as solid phase. Branson Sonifier® SFX250 was used for emulsion formation (based on the principle of ultrasonic processing). All the experiments were performed for the same conditions of 5 minutes of ultrasonic processing at an output power of 30 W by using 6.5 mm tapered microtip (sonication probe). Emulsion characterization was done by using an optical microscope (Axio Scaope.A1).
Several combinations of water-oil-fines were tested. The tests consisted of control experiments (in which only water-oil without any fines were tested) and water-oil-fines experiments. In the control experiments (without fines), SSW did not show any tendency to emulsify neither with the model oils nor with NSCO. However, DIW showed clear tendency to emulsify with model oils and NSCO. Amongst model oils, DIW emulsified with HH better compared to decane. Similar results were observed in the water-oil-fines experiments. SSW did not form any emulsion with the model oils in the presence of fines of CaCO3 and CaSO4. However, significant amounts of emulsion formation were observed when DIW was sonicated with model oils and fines. HH formed more emulsions compared to decane. For NSCO case, both SSW and DIW formed a significant amount of emulsions with both types of fines (CaCO3 and CaSO4). An increase in amount of fines showed an increase in emulsion formation and a better emulsion stabilization. Sonication is a quick and reliable technique to screen out emulsion formation in different combinations of water-oil-fines.
This work will further develop our understanding of emulsion formation in the water-oil-fines systems.
Dernaika, Moustafa R (Ingrain Inc) | Sahib, Mohammad Raffi (Kuwait Oil Company) | Gonzalez, David (Ingrain Inc) | Mansour, Bashar (Ingrain Inc) | Al Jallad, Osama (Ingrain Inc) | Koronfol, Safouh (Ingrain Inc) | Sinclair, Gary (Ingrain Inc) | Kayali, Anas (Ingrain Inc)
Detailed core characterization is often overlooked in the sampling process for core analysis measurements. Random core sampling is usually performed and the selected plugs are not associated with rock types or the reservoir heterogeneity. The objective of this study is to obtain representative samples for direct simulation of petrophysical and fluid flow properties in complex rock types.
A robust sampling strategy was followed in reservoir cores from two successive heterogeneous carbonate and siliciclastic formations in the Raudhatain field in Kuwait. The sample selection criteria were based on statistical distribution of litho-types in the cores to ensure optimum characterization of the main reservoir units. The litho-types were identified based on porosity and mineralogy variations along the core lengths utilizing advanced dual-energy X-ray CT scanning. High resolution micro-CT imaging and subsequent segmentation provided 3D representation of the pore space and geometric fabric of the core samples. Primary drainage and imbibition processes were simulated in numerical experiments using a pore-scale simulator by the Lattice Boltzmann Method. Capillary pressure (Pc) and relative permeability (Kr) curves together with water and oil distributions were investigated for complex geometries by the different rock types.
The dual energy CT density was compared with wireline log and provided accurate calibrations to the downhole logs. The different rock types gave distinct capillary and flow properties that can be linked to the rock structure and pore type of the samples. The Lattice Boltzmann based pore-level fluid calculations provided realistic fluid distributions in the 3D rock volume, which are consistent with pore-scale physical phenomena.
This characterization method by the dual energy CT eliminates sampling bias and allows for each cored litho-type to be equally represented in the plugs acquired for subsequent petrophysical and fluid flow analyses. It also provides accurate calibration tool for downhole logs. The digital analysis gave reliable SCAL data with improved understanding of the pore-level events and proved its effectiveness in providing advanced interpretations at multiple scales in relatively short timeframes.
Unlike conventional reservoir development, uncertainty analysis and design optimization of unconventional reservoirs have caught less attention because of a general notion that oil field production data analysis and computational methodologies and techniques can be applicable to unconventional reservoir developments. In order to predict production profiles in unconventional reservoirs, it is essential to understand the uncertainties and performance of unconventional reservoirs. In this paper, the most relevant factors influencing the production of gas-condensate in a domain of real data from gas condensate fields is investigated and reviewed. To identify the major factors affecting the production of condensates from heterogeneous and ultra-low permeability reservoirs, third and fourth order factorial design (Box Behnken technique) were used on a domain of gas-condensate field data to perform the uncertainty analysis. A semi-analytical surrogate model for Monte Carlo analysis was also proposed in this paper. Condensate blockage radius, reservoir permeability, well spacing, reservoir thickness; compressibility, initial pressure; fracture spacing and initial condensate saturation were noted to be the most substantial parameters influencing condensate production. Validation of the results proved that the proposed surrogate models for gas-condensate reservoirs could reliably be used to forecast condensate values in heterogeneous and ultra-low permeability reservoirs. This paper also presents a semi-analytical model applicable to unconventional reservoirs to incorporate the effect of condensate banking in the design optimization of hydraulic fracturing. Analytical models for Darcy flow above and below the dew point pressures were considered whilst estimating the optimum fracture design in gas condensate reservoirs using Schechter's approach incorporating the effects of the condensate blockage radius.
To improve Oil production rates and recovery factors North Kuwait shifted its exploitation strategy from vertical to horizontal completions. These horizontal ICD completions did indeed reduce the draw down pressure within the reservoir, thereby delaying water breakthrough. When water did eventually breakthrough, there was no completion mechanism to effectively control the conning effect, other than choking back/reducing the flow rate further with the consequent further loss of oil production. Additionally, water shut-off opportunities in passive ICD-completed wells were limited and marginally successful, since the water moves laterally along wellbore to adjacent compartments. The coning control completion (CCC) technology is an excellent emerging technology for improved oil recovery from water drive reservoir.
The coning control completion (CCC) technology, applicable only in vertical or moderately-deviated wellbores (< 60°), is a technology that revolutionizes the development strategy of water drive reservoirs. The fundamental principle of this technology is to create a pressure drawdown, or pressure sink (ΔP), at or just below the OWC within the water leg, equal to or marginally more than the ΔP across the perforated interval within the oil leg. This drawdown retards the progression of water cone into the oil column and can be achieved using an inverted, bottom-discharge high-volume ESP. A preferential flow of the bottomor edgewater is created, parallel to the bedding plant, just under the OWC. The disposal options for the diverted water is either to "dump" into an under lying aquifer, or to preduce to surface for processing and re-injection, if necessary.
For the interval perforated, the candidate well flowed naturally at rates six (6) times the calculated critical coning rate with a subsequent early water breakthrough resulting in a 45% loss in oil production. After commissioning the inverted ESP system water cuts have not only decreased by 50%, but also stabilized. After a planned or unplanned ESP shut down, the water cone redeveloped, but was brought under control again, and water cuts reduced and stabilized accordingly. Flowing BHP at the oil perforations, ESP intake pressure, and watercut are all monitored closely to ensure the watercut from the oil perforations are maintained at an optimum level, but not allowed to disappear. ESP rates are estimated by correlating the intake and discharge pressures from the specific pump curves.
With inverted ESP's the coning control completion technology facilitates reduced surface water production while increasing oil production from partially-perforated oil columns at much higher than critical coning rates. A direct benefit is derived from subsurface disposal of the pressure-sink water to underlying aquifers within the same wellbore, significantly reducing surface water processing, handling, disposal and associated operational cost.
Grijalva, O. (Clausthal University of Technology) | Perozo, N. (Clausthal University of Technology) | Holzmann, J. (Clausthal University of Technology) | Paz, C. (Clausthal University of Technology) | Oppelt, J. (Clausthal University of Technology)
Developments in OCTG connections defining well integrity and mechanical performance of oilfield tubulars are not something newas a continuous feedback between field challenges and theinnovative nature of the Industry is something derivated into newer, more intensive Full Scale Testing procedures and novel analytic tools for connection performance evaluation in the last decades. The relationship between all those factors has been condensed in the present paper which gives shape to a comprehensive "technical history" for Premium Connections, hidden and scattered so far in issued patents, manufacturer manuals, brochures and selected field cases generated between 1935 and 2017. Design schools can be well defined by manufacturer and region;apart from this, theadvancements in testing and manufacturing made possible to adjust the connection to the technical constraints put fromthe field, namely a high need for gas tightness and enhanced torque capabilities. Last but not least, it was discovered that, among all oilfield equipment used during upstream operations, it was (next to advancements inSSSV's)the constant evolution of tubular connectiontechnologieswhat contributed to "crystallize" the modern concept of Well Integrity, especially after the big offshoredevelopments seen from 1971 on. As a corollary, the impact of current standardization protocols ISO 13679 / API 5C5 on well integrity in terms of metallic seal integrity will be assessed in the light of the tribological and mechanical evolution of the MTM seal during testing and validation.
Some heavy oils reservoirs present an unusual behavior when put on production under significant drawdown conditions. In these reservoirs, the high formation depressurization increments the recovery factor and accelerates the production rates driven by a solution gas mechanism. Due to the chemical and physical properties of these oils they tend to stabilize the dispersion of gas bubbles, promoting the generation of foam in the oleic phase. This foamy oil when compared with conventional oils result in a more productive response at similar drawdown conditions. The foamy oil phase behavior is the result of a number of complex mechanisms and requires a good understanding on each of them to estimate the potential response of these reservoirs. In this work, the role of key factors that affect the bubbly oil production is summarized.
To outline the significance of key variables on the performance, a commercial optimization and uncertainty analysis software coupled with a mechanistic simulator is used. The simulator allows a detailed modeling of the physics involved on the generation and behavior of the foamy oils, in which the foamy oil is modeled as a disperse phase of gas bubbles in the oleic phase, including small mobile gas bubbles and larger trapped gas bubbles flowing as discontinuous gas dispersion which affect foam viscosity, compressibility, mobility and relative permeability. Fluid properties used in this work are from
The sensitivity and optimization analysis performed in this work on key reservoir variables and well operational parameters shows the significance of each factor on the production response. The relative importance of each variable is reported in tornado diagrams. Results showed that a strong approach on handling the reservoir unknowns are as crucial as the control of operational parameters from reservoir management point of view.
Nowadays the foamy oil behavior and its favorable production response are not totally well understood. Solutions have been proposed but they are still controversial and the use of horizontal wells introduces more complexity in the production operations. In this work is provided an in-depth optimization and uncertainty analysis to outline the role of each major parameter affecting the production response and the recovery efficiency in this type of reservoirs using horizontal wells.
A detailed understanding of the composition of sour gas accumulations is essential for facility design and for production forecasting. Compositional data like H2S and CO2 contents, net sales gas volume and condensate gas ratio also form the basis for all project economics. The acquisition of high quality fluid compositions is therefore a priority in all sour gas well evaluations. For conventional gas accumulations, PVT analysis of down-hole or well-head samples provides accurate and representative compositions of reservoir fluids. But in many sour gas accumulations, like the Marrat in North Kuwait, the prediction of future production streams is a difficult task. H2S levels are highly variable and the ‘point measurements’ from MDT fluid samples may not be representative for the entire reservoir unit. This paper describes a new approach to derive gas compositions from the analysis of core samples so that PVT compositions can independently be verified and H2S concentrations can be extrapolated away from the down-hole sampling points. The method is illustrated with two wells from an ultra-sour gas field in the Arabian Gulf region.
Core and cuttings samples from gas reservoirs contain trace amounts of adsorbed gas and condensate, which can be thermally extracted. The desorbed fluids can then be analyzed using existing geochemical technology and the molecular compositions of the condensate can be used to derive the composition of the gas that was trapped in the reservoir. Carbon isotope ratios can be measured on the gas that is desorbed from core samples and provide a second, independent parameter to estimate the original gas composition. The obtained fluid distributions are used to reconstruct the filling history of the sour gas accumulation.
The isotopic signature of the gas, together with the composition of the organo-sulfur compounds in the condensate, allow the reconstruction of fluid compositions, which are a critical input parameter for the reservoir simulators. Combining the results from the geochemical analysis with existing PVT data allows the extrapolation of the fluid compositions and the reconstruction the field-wide compositional gradients.
With H2S and CO2 concentrations varying between 5 and 35%, the production forecasting of sour gas accumulations can be subject to large uncertainties. Reconstructing the gas compositions from core and cuttings samples with geochemical techniques substantially reduces these uncertainties.
Sabiriyah Mauddud and Upper Burgan are two of the giant reservoirs in North Kuwait(NK) under active water flood since 2000. About 400 MBWPD of water is currently being injected to maintain the reservoir pressure & improve the production/recovery. A comprehensive workflow process was developed and implemented to understand the waterflood performance, pressure-production response trends and map the opportunities to encash the benefits in terms of quick oil gains. The paper discusses the best practices adopted to increase production from two of the water flooded reservoirs in NK.
Sound workflow process was created by integrating the technical inputs under collaborative environment from subsurface & surface teams. Series of segment reviews are conducted to understand the connectivity between producers & injectors, duly integrating all surveillance data. Analytical diagnostic tools have been used to distinguish between the good water and bad water and improve the VRR & sweep. Live ESP data is monitored and tracked at intelligent field collaboration centre to decide about the actions for the wells requiring ESP upsizing, downsizing and VSD/choke optimization. Wells with running ESPs were identified for VSD & choke optimization, using rationalized technical criteria. Wells with failed ESPs are reviewed for smart replacements with water shut off/water flood conformance & ESP re-design. Simultaneous actions for the well model creation; running sensitivity and scheduling in the workover rig are taken up.
ESP upsize, along with VSD installation/choke optimization, was implemented in number of wells with significant oil gain (about 11% enhancement within a short time frame). As a part of the process established, this activity has become a regular practice in NK. Such wells are under constant monitoring so that water injection actions in nearby injectors, if needed, could be taken up such as allowable management, arresting the declining trend etc. The benefit of mega water flood activities have been reaped in terms of production enhancement adhering to the best reservoir management practices.
Quick understanding of the Water flood response and relignment of actions on the associated wells via rigless and rig workovers is the key to the success for significant ramp of the NK production within a short time window of 6-7 months. Several work flow processes established during the campaign are now deeply imbeded within NK asset.
Inflow control devices techniques started to be widely used in North Kuwait filed (NK) where it delivers a valuable mean of managing production and simultaneously control the water cut and gas breakthrough. Drawbacks, such as port plugging and limited intervention options to the reservoir are also dealt with as a risk factor. In North Kuwait, some wells started to show production decline. Finding the root cause and identifying that it is related to formation damage or ICD-completion issue is necessary to define and plan for proper intervention in order to restore the productivity.
One of the key and initial confirmations required is the ICD completion’s integrity, the assurance of the ICD ports to be open and contributing to production. This can be identified by either PLT or ILT, needing multiple activities and interventions to decide for remedial actions and to design a proper well intervention. Real-time coiled tubing profiling tool is a coiled tubing conveyed tool that enables real time injection profiling that helps in real time in confirming the port status if open or plugged. Meanwhile the CT itself during the same run can be utilized for the planned treatment to stimulate or remove any asphaltene/scale deposit.
In Sabriya Field, Well-0X, a real-time coiled tubing profiling tool was utilized in ICD completion to deliver ILT profile in real time mode. Coiled tubing profiling is a powerful tool that can be run easily with CTU. It reduces the risks of using H-PLT/H-ILT in HZ wells. The tool shows a good match during the injection profile with DTS profile. The identification of the cease to flow root cause was easily identified (the quantitative injection profile across ICD compartments shows the compartments of low injection and the compartments of high injection rate). It was planned to perforate the ICD completion based on the initial findings from the previous intervention that will be resulted in losing ICD integrity and main function.
Thereafter, based on the finding, a trial of wax and asphalting treatment was pumped to enhance the well productivity before moving forward for ICD perf option. Hence, in single run, an injection profile to identify the plan and injection of treatment followed by a second injection profile to confirm status of the ports were conducted which helped to restore the well productivity thereby multiple interventions and deferred production.
Based on the results, the right corrective action was selected avoiding ICD perforation thus selecting the right decision that helped in restoring the well productivity and saving costs while maintaining ICD integrity and main function. The well was successively put back onto production with a normal flowing rate. The planned and executed job has helped to restore production with best practice. This practice and work flow have been accepted to be implemented in similar wells in future.
Al-Mutairi, Abdulaziz (Kuwait Oil Company) | Baqer, Hussain Ali (Kuwait Oil Company) | Dhabria, Akshaya Kumar (Kuwait Oil Company) | Rook, Gert-Jan (Shell Kuwait) | Shaik, Ahmed Karim (Shell Kuwait) | Al-Mutairi, Bandar (Kuwait Oil Company) | Hii, King-Kai (Shell Kuwait) | Hadi, A. A. (Packers Plus Energy Services)
The optimum development of the Deep Carbonate reservoirs in North Kuwait is key to achieve KOC's gas production targets. To optimize (future) production and accessibility of the various Flow Zones within the Target MT formation, KOC has selected a 4.5" mono-bore design to complete the North Kuwait Gas wells. To further improve understanding of production contribution from different flow zones and to enable selective stimulation and effective testing of flow zones, a trial was conducted in a new well to install a 4.5" 15K rated open-hole Multistage Completion (MSC).
The well trajectory was designed with all directional work done before the reservoir section. The deviated reservoir section was drilled successfully to the planned TD. A three stage MSC with a long tail string (for future access to deeper reservoirs) was successfully installed. The bottom and middle stages were successfully stimulated and production tested. Stimulation and testing of the upper stage is planned for the future.
To build on the success of this first trial another candidate well has been identified and a second 15K MSC system is expected to be installed in the second half of 2017.
This paper describes the best practices and the learning in planning and installation of a first successful open-hole MSC in a High Pressure gas well in Kuwait, as well as recommendations for future MSC installations in deep high pressure gas wells with large variations in reservoir caracteristics.