Conventional strategy for developing of giant oil reservoirs with a gas cap involves an optimal production from the oil column before the gas cap is blown down. This paper investigates technical aspects of co-development strategies where demand for the gas may entail earlier exploitation of the gas cap along with the existing oil column development.
Co-development of giant reservoirs with condensate-rich gas cap are particularly challenging due to the presence of significant condensate volumes. The basic strategy of the co-development plan involves producing from a gas cap first under full gas recycling so as to accelerate condensate recovery. This is followed by sales gas production by means of partial gas recycling in conjunction with water injection at gas-oil contact for pressure maintenance purposes. The injection of water at gas-oil contact is intended to provide a water barrier or fence that separates and / or minimize gas cap expansion toward oil. The degree at which sales gas is produced is under pressure maintenance scheme is thus linked to the level of the partial gas recycling and the efficiency of the barrier or fence water injection.
To explore the feasibility of this process, reservoir simulations of mechanistic models were first used to study the reservoir physics of water injection at gas-oil contact for the purpose creating water barrier and /or fence. This was followed by implementation of the co-development scheme using sector models that represent two giant carbonate gas cap reservoirs. The feasibility and merits of the co-development strategy were measured by performance metrics that include condensate recovery, sales gas production, minimum oil loss and fluid migration at gas-oil contact and overall water demand.
The results show that partial recycling along with barrier water injection may provide a mechanism for concurrent gas cap and oil column exploitation. A key factor that underlies the success of the co-development plan is the ability of the water injection at gas-oil contact to recover potential pressure drop in time as gas recycling ratio is reduced by forming effective barrier. This, in turn depends mainly on the reservoir geology and water injection volume and scheme. Moreover, reservoir characteristics that are favorable to the process are lower formation dip angle, smaller surface area at fluid contact and good injectivity of the reservoir rock.
In recent years, low salinity flooding has attracted significant attention as a new method for improving/enhancing oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of low salinity injection are available in the literature, which show a wide range of responses in the extra oil recovery, ranging from 0 to more than 20%. In this paper, we report experimental programs performed using cores and fluids from several reservoirs in Abu Dhabi with the objective of quantifying low salinity effect in both secondary and tertiary modes and to establish a procedure to screen reservoirs for their suitability for low salinity waterflooding.
To quantify the low salinity effect, multi-rate unsteady state flooding experiments have been performed in both secondary and tertiary mode using reservoir fluids and core material at reservoir conditions of 120 C and 4000 psi. All core floods were performed using 30 cm long and 2 inch diameter core samples. In addition, fluid-fluid interaction experiments were performed using fluids from more than 20 carbonate reservoirs in Abu Dhabi. The fluid-fluid experiments were performed to measure the water in oil micro-dispersion formed upon contacting crude oil with both formation water and low salinity water in order to screen ADNOC's oil reservoirs for suitability for low salinity waterflooding.
The fluid-fluid interaction experiments showed that a number of crude oil samples from carbonate reservoirs in Abu Dhabi were able to create micro-dispersion upon contact with low salinity water. These crude oils are called positive crudes in this paper. On the other hand, several crude oil samples did not show micro-dispersion upon contact with the same low salinity water, hence they are referred to as negative crude oils. Two positive crude oils and two negative crude oils have been used in the flooding experiments. The main conclusions of the study are: 1- The flooding experiments using positive crude oil samples have led to extra oil recovery upon injecting low salinity water, while the negative crude oil resulted in either no or little extra recovery, 2- The data base developed in this study is used for screening ADNOC's oil reservoirs for low salinity waterflooding based on fluid-fluid interaction and shows a significant potential of this promising EOR technology for carbonate reservoirs, and 3- The flooding experiments show up to 6.5% extra recovery in tertiary mode and up to 12.5% extra recovery in secondary mode.
The study presented in this paper demonstrates that the use of fluid-fluid interaction experiments and measuring the creation of micro-dispersion upon contacting crude oil with low salinity is a robust screening method for low salinity water flooding. Moreover, this screening method can lead to significant saving in both time and cost of running low salinity flooding experiments.
This paper discusses the urban planning process applied for field development of one of the biggest and most congested field in sultanate of Oman. The field has a carbonate reservoir contains a light oil with associated gas. The reservoir is currently under waterflood development. The oil production is co-mingled with other fields at production station and the produced water is pumped back into the reservoir for pressure maintenance and the remaining is disposed into another reservoir. The field contains an area layout of 22 km °18 km. The new development proposal of further infill drilling at a narrower spacing was challenging in term of well interference with existing infrastructure, spacing, rig movement and accessibility.
The first pass of checking the wells locations feasibility shows that only 30 percent of the wells can be drilled due to massive amount of existing wells with surface infrastructure. It was not easy to develop and drill the majority of proposed wells with required surface infrastructure. A detailed urban planning study was carried out to address the inherent issues and challenges associated with re-development of the field. An integrated multi-discipline team was formulated consisting of, Concept Engineering, Geomatics, Production Geologist, Reservoir Engineering and Well Engineering. A close coordination was also maintained with other relevant disciplines to address the surface development issues and for making the quality concept decisions in early phase of the project. The process of urban planning applied in this study was documented as a best practice within the company and cross learnings were used as basis during the study and also captured in Urban Planning Guideline which was developed internally.
Resolving the challenges for placement of wells on surface and rig accessibility for drilling challenged the normal ways of working and triggered the un-conventional thinking to establish the well drilling feasibility and integration with surface scope. Consequently, project team have come up with ways to drill the wells that would not be drilled by following the normal way of working. Integrated urban planning enabled the proposed number of wells to be drilled despite the insufficient space to accommodate standard pits and pads. In conventional approach, initial urban planning assessment concluded feasibility of drilling only 30 percent of proposed wells. However, the team managed to improve the feasibility of drilling those wells up to 90 percent. This has allowed the maturation of the planned target hydrocarbon volume and created huge value in re-development of this field. Tangible benefits also achieved in early decision-making, up to two months schedule acceleration could be realized in field development through integrated urban planning approach. Study has demonstrated that urban planning can save approximately 10 percent in off-plot CAPEX. On top of this, urban planning has helped in lowering HSE risks during the drilling and reducing production deferment during construction.
Meziani, Said (ADNOC) | Ghorayeb, Kassem (American University of Beirut) | Al Zaabi, Najla (ADNOC) | Hafez, Hafez (ADNOC) | Al Katheeri, Abdulla (ADNOC) | Maldonado, Jorge (Schlumberger) | Khattak, Iftikhar (Schlumberger) | Haryanto, Elin (Schlumberger) | Chabernaud, Thierry (Schlumberger) | Yersaiyn, Saltanat (Schlumberger) | Kumar, Sayani (Schlumberger) | Shahid, Shawwal (Schlumberger) | Agam, Abdelrahman (Schlumberger) | Shah, Abdur Rahman (Schlumberger) | Chakraborty, Subrata (Schlumberger)
This paper describes a pragmatic approach for reviving a highly depleted major Oil Rim Reservoir after more than 30 years of massive gas cap exploitation. The main objective is to assess options and identify the optimal plan to re-develop the Oil Rim while honoring and not jeopardizing the gas and condensate production of the network and the existing facility constraints.
An integrated workflow was designed and implemented to understand the reservoir geology, field production history and to address requirements of both oil rim and gas cap developments. Analysis started by a dynamic synthesis to track oil/water contact (OWC) and gas/oil contact evolution with time using available surveillance data: MDT pressure gradient analysis with petrophysical evaluation (RST & OH logs).
A study consisting of a comprehensive review and update of the static and dynamic models was carried out to ensure the model adequacy for robust re-development planning. The dynamic model quality was assessed by comparing dynamic model results with surveillance data especially with regard to predicting the contacts movements and pressure variation vs. time in the different regions of the Oil Rim.
Production forecasting and optimal re-development plan identification followed a systematic approach aiming at assessing the incremental impact on oil recovery through the utilization of artificial lifting, different types of wells and completion as well as a variety of water injection scenarios. Sensitivity analysis included horizontal well lengths, well density, well placement, water injection and production capacity as well as economic constraints.
Oil production from this low-pressure oil rim reservoir has been a challenge due to the spread oil resources and complicated production mechanisms. The movement of OWC and GOC has been very sensitive and caused unfavorable early water/gas breakthrough. Despite the low recovery factor, some attempts to revive dead oil wells through artificial lift means (ESP, booster pumps) were made and considered as an initial step to reactivate the inactive wells.
The low oil production volume and hence low recovery makes the oil rim re-development economically less attractive. However, integration of state-of-the-art engineering approaches, proposed innovative technical initiatives and new technologies create an opportunity for significantly more economically attractive re-development.
The workflows used and discussed in this paper were tested for four other oil rim reservoirs and can be implemented in similar challenging oil rim development projects.
A nanosilica based fluid system was evaluated for forming in-situ glass-like material inside matrix for permanent gas shutoff. This novel method involves two steps; firstly, pumping low viscosity aqueous nanosilica mixture into the formation and allowing it to gel up. Secondly, gas production dehydrates nanosilica to form glass-like material inside the matrix. For this paper, a nanosilica-based fluid system was assessed for pumping strategy and performance evaluation.
A nanosilica based fluid system consists of a mixture of colloidal silica and activators. It possesses low viscosity, which assists in deeper penetration during placement. With time and temperature, it can lead to in-situ gelation to form a rigid gel to block the pore space. Gas production can dehydrate nanosilica gel to form in-situ glass-like material inside formation porosity for permanent gas shutoff. The nanosilica based fluid system was optimized using gelation tests and core flooding tests to evaluate its performance under high-pressure, high-temperature conditions. Formation of in-situ glass-like material inside pores was analyzed using a scanning electron microscope (SEM).
The gelation time can be tailored by varying the activator type and concentration to match the field operation requirements. Kinetics of colloidal silica gelation at elevated temperatures showed faster viscosity buildup. Before gelation, the viscosity for the nanosilica based fluid system was recorded less than 5 cp at a 10 1/s shear rate, whereas the viscosity was increased more than 500 cp at a 10 1/s shear rate. Using core flow tests, N2 gas permeability of the Berea sandstone core was completely plugged after pumping the 5-pore volume nanosilica based fluid system at 200°F. During nanosilica based fluid system injection through the core, differential pressure was increased to only 10 psi showing better injectivity. The SEM images showed the presence of glass like material filling the porosity, which showed in-situ generation of glass-like material inside pores.
The nanosilica based fluid system has a low viscosity and can penetrate deeper into the formation matrix before transforming into a gel. Undesirable gas flow can dehydrate nanosilica gel to form in-situ glass-like material inside matrix for permanent sealing. This is environmentally friendly and can serve as an alternative to currently used conformance polymers for gas shutoff applications.
Wu, Xingcai (Research Inst. of Petroleum E&D,CNPC) | Wang, Yongli (Daleel petroleum L.L.C) | Al Naabi, Ahmed (Daleel petroleum L.L.C) | Xu, Hanbing (Research Inst. of Petroleum E&D,CNPC) | Al Sinani, Ibrahim (Daleel petroleum L.L.C) | Al Busaidi, Khalfan (Daleel petroleum L.L.C) | Al Jabri, Saleh (Daleel petroleum L.L.C) | Dhahab, Salah (Daleel petroleum L.L.C) | Zhang, Jianli (China National Oil and Gas E&D Corporation) | Xiong, Chunming (Research Inst. of Petroleum E&D,CNPC) | Ye, Yinzhu (Research Inst. of Petroleum E&D,CNPC) | Tian, XiaoYan (Startwell Energy Technology Co. LTD) | Jia, Xu (Research Inst. of Petroleum E&D,CNPC) | Lv, Jing (Research Inst. of Petroleum E&D,CNPC)
The field under study is located in the northern part of Oman where most of the fields have a tight carbonate oil reservoirs. Initially the field was produced under natural depletion for almost 15 years until 2005 when a line drive water flood development with horizontal wells took place and was deployed in the whole field. After more than 10 years of water injection, the water cut reached an average of 75% in the major producing blocks. The reservoir has a light oil with viscosity of 0.8 mPa.s, a downhole temperature of 87°C and average permeability of 10 mD. The calcium and magnesium concentration in formation water is high, about 4000 mg/L.
Reservoir heterogeneity in tight carbonate reservoirs causes uneven water flood sweep efficiency and hence resulted in a lot of bypassed oil. The initial EOR methods screening in the field under study didn't recommend to use the conventional polymer flooding due to low reservoir permeability and hence injectivity challenge. However, a new unique nano-ploymer was recently developed in the market to be a potential EOR method for such tight formation reservoirs. Extensive laboratory experiments using the core and fluid samples from the studied reservoir followed by numerical simulation modeling work proved the technical feasibility for this new polymer. This was then followed by field testing pilot in one of the matured water flood sector and the performance is currently under monitoring.
The new polymer is a particle-type and comes with various nanometer-micrometer sizes. This polymer has a low apparent viscosity of 1-4 mPa and when it is mixed with the injection water, the particles disperse in the water and the resultant mixture has a low viscosity making it easily to be injected. In addition, this nano-polymer has a high tolerance for both temperature and salinity. While the particles move into formation, they temporarily plug the preferential existing water paths and divert the injection water into the relatively small pores/throats and displace the remaining bypassed oil. The polymer particle has high deformation capacity, so it can deform and pass through the throat under certain pressure to plug even deeper parts of the formation. The process is repeated continuously so that it can inhibit water production and enhance oil production.
For the lab experiments, 12 core plugs from the associated reservoir were collected, based on which, a series of experiments were conducted including: core thin section analysis, injectivity test for the nano-polymer and core flooding experiments on single plug and parallel double plugs. Subsequently, the lab results were utilized for numerical simulation and that was followed by economic evaluation.
Based on the lab test results, a conceptual simulation model for the studiedfield's sector was used to estimate the incremental oil gain at different pore volume (PV) injection. The incremental oil gain was determined at different SMG PV injection starting from 0.05PV to 0.5 PV. The results showed that the best economic scenario is to go for PV injection of 0.3 which can be achieved in ~4 years'time. However, in order to expedite the field trail stage and reduce its cost, the lowest PV injection was selected which involves injection in two water injectors for one year only at 0.05 PV.
The field pilot thus far has successfully completed the injection phase of the total planned volume (0.05 PV) of nano-ploymer. The injection was continuous for one year with no injectivity issue and the production performance is currently under monitoring.
Global oil demand has led to the development of new smarter drilling, completion, reservoir management technique and technology to optimize reservoirs production. The production of Kuwait Oil Company (KOC) has reached 3 MMBOPD and KOC’s 2030 vision is to boost the production to 4 MMBOPD. In order to achieve this vision, KOC has started several technical projects and development plans. One of these projects is the North Kuwait Integrated Digital Oil Field (NK-KwIDF) a full-fledged Field project implemented in KOC.
This Paper will discuss the scale, complexity, technology used, and advantage of using the NK-KwIDF. The North Kuwait (NK) asset has five fields, around twelve hundred active wells, and seven Gathering Centers (GCs). A complex network of pipeline, trunk line, and manifold are used to connect these twelve hundred wells to GCs. In order to optimize the production from NK every barrel of production opportunity has to be considered by optimizing suitable wells and minimizing downtime from each field, resulting the development of an extensive surface network model. The extensive surface network model takes into consideration of each and every details of field e.g. pipelines, manifolds, details of GCs and wells. For each and every well in NK assets a well model is prepared considering all PVT parameters, completions, and surface co-ordinate and finally connected to surface network model with all piping information.
Once the extensive surface model was prepared, several integrated workflows were developed in order to efficiently run the surface model and analyze the output from the run. Some of these workflows are ESP Optimization and ESP Analysis workflows, which have capability to identify the Oil Gain Opportunities and diagnose ESP performance. The identify opportunities are logged into ticketing system, which monitors the life cycle of the opportunity right from the identification till implementation into the field for Oil Gains.
The full-fledged development of NK-KwIDF took almost 3 years from the day it was started, as a pilot project with 133 wells. When an excellent result in terms of production optimization and downtime minimization was recorded from the pilot project, the pilot project was expanded to full-fledged field project. The NK-KwIDF project gave an outstanding result of Oil gain from well level as well as Network level optimization. It established an excellent reputation in the oil industry where it was a source of attraction for many NOC’s and IOC’s to visit and follow the flag ship for their development and implementation of digital field technology.
Reliability engineering unit conducted comprehensive and detailed study of machinery lubrication systems for salt water injection pumps and gas compressors operating at various facilities of north Ghawar producing department of Saudi Aramco to achieve lubrication excellence. As a part of lubrication study, data from the following sources was collected, analyzed and gaps were addressed for better contamination control to enhance equipment reliability and compliance KPI.
Mahajan, Sandeep (Petroleum Development Oman, Sultanate of Oman) | Behera, Chaitanya (Petroleum Development Oman, Sultanate of Oman) | Hemink, Gijs (Petroleum Development Oman, Sultanate of Oman) | Hamdoun, Lana (Petroleum Development Oman, Sultanate of Oman)
The Amin field located in South Oman is one of the PDO's major producing oil fields. The reservoir is good quality sandstone formation with average porosity of 28% and average permeability of 800 mD. Prior to 2014, the field was developed using natural depletion drive during which some parts of the field experienced significant pressure depletion. This depletion was due to combination of high production from the crestal area and the presence of a near field-wide intra baffle (L110), that restricts the aquifer response to the upper layers of the reservoir. The baffle about 2m to 4 m thick is a cemented sandstone with minor shale intercalation that has caused the vertical pressure variation across baffle L110.
To arrest the field pressure depletion, water-injection was implemented since 2014, for further field development. Produced water is injected into the aquifer below the OWC of the field through 38 vertical injector wells. To achieve desired voidage replacement injection is expected with fracturing conditions using untreated produced water with injection rates > 1500 m3/day. Bottom hole pressures are at or above formation fracture pressure and decline in injectivity with time has been observed due to untreated water.
Geomechanical data and modeling results were integrated with WRM activities, trials data and surveillance technologies to optimize the injection strategy for improved waterflood performance. Geomechanical data was acquired to estimate the formation fracture pressure to provide guidance on maximum allowable injection pressure in injectors with perforations closer to OWC to manage the risk of induced fracture growth. A Produced Water Re-Injection (PWRI) fracture modeling and analysis was performed to determine the potential fracture dimensions to provide input to development decisions of injection rate and perforation depth below OWC. Simulations were carried out with estimated range of formation fracture pressure, Petrophysical parameters, injection rate forecasts and expected water quality parameters e.g. TSS (Total Suspended Solids)
The simulation results from the field data calibrated PWRI fracture model indicate that injection higher rates > 1500 m3/day, would result in vertical fracture growth from the injection depth. The rate of fracture growth is primarily influenced by water quality and depth of injection. Formation fracture pressure decreases with depletion therefore once the vertical fracture propagates and enters into the upper reservoir zone, fracture growth will be accelerated. Results indicated that if injection depth closer to OWC can result in short-circuiting as early as 2 years for certain field area.
Higher injection rates to meet the desired voidage replacement ratio has significant impact on the field's waterflood performance. Results provided inputs to reservoir simulations and injection rate envelope for varying perforation depth below OWC. The study benefits the field to minimize risk of injector producer short-circuiting for improved waterflood management.
A reservoir simulation study of different fishbone well designs performance compared to a base development well design of extra-long maximum reservoir contact (MRC) single lateral wells is presented. The objective is to compare different well design concepts in a waterflood recovery scheme to achieve production target rate and maximize resource value for economic development of an undeveloped tight carbonate reservoir. The studied reservoir is located in a giant offshore oil field in the Middle East and was used as a representation of the different tight reservoirs within the field. It is characterized by poor quality rocks with a permeability trending from 2 – 0.5 md in a SE – NW direction.
The study compromises an assessment of the achievable initial maximum oil rate, volumetric reservoir sweep and expected ultimate oil recovery factor for different well design concepts for a base short well spacing utilized for effective pressure support. In addition to that, the impact of fishbone well design on well count reduction potential utilizing twice the base short well spacing compared to single lateral wells development design utilizing the base short well spacing was evaluated.
A sector model with equal producer to injector ratio was used with refined gridding to wells and bulk area gridded with a cell size of 10 m by 10 m in a representative area of the reservoir. The modeled wells incorporated with vertical flow performance tables with gas lift capabilities. The analysis also incorporated generating streamlines for analyzing fishbone well designs areal reservoir sweep and an examination of remaining movable oil areal distribution. An assessment matrix was formulated for comparing extra-long MRC single laterals base development design versus different fishbone well designs. The assessment matrix incorporated in addition to reservoir related flow performance indicators: drilling complexity and well cost, well life cycle activities, etc. for a comprehensive assessment.
The main findings show that fishbone well designs have complicated areal sweep performance, especially with sealed motherbore, that result in a lower oil recovery factor with higher hydrocarbon pore volume injected and water oil ratio compared to extra-long MRC single laterals. Also, fishbone well designs have serious limitations during well life cycle activities compared to extra-long MRC single lateral design in terms of stimulation, well accessibility and well intervention options making the extra-long MRC single laterals the preferred field development concept within tight reservoirs especially with the base short well spacing. Finally, the analysis has shown that Fishbone well designs can't reduce the well count since base short well spacing is still needed for effective pressure support by water injection in addition to maximizing the oil recovery factor within the field life time and building and sustaining the target plateau.