Jin, Fu (CNPC Drilling Research Institute) | Shunyuan, Zhang (CNPC Drilling Research Institute) | Bingshan, Liu (CNPC Drilling Research Institute) | Weiwei, Yin (China United Coalbed Methane Corporation, Ltd.) | Chen, Chen (CNPC Drilling Research Institute)
It is estimated that tight oil takes up 46% of the total reserve volume, including conventional tight oil, super-tight oil and ultra-tight oil whose viscosity is 5.8×104mPa·s (degassed crude oil at 50°C). Some tight oil resources are 600-900m deep, while others are found in deep formations (1300-1700m). In order to deal with sand production and low recovery rate integrated researches on super-tight and ultra-tight oil buried in deep formations have been accomplished.
A group of 7 wells were selected and the overall steam stimulation was simulated by software. All modified chemicals such as the high temperature frothers, high temperature gel particle plugging agents and special resins were tested in labs in order to prove their performance, while downhole tools had been applied in adjacent wells. At last the average sweep efficiency and oil production rate of wells in the group were compared with that of adjacent wells.
Casing programs, horizontal sidetracking technologies and slim hole cementation technologies shall be optimized to extend the well's life. The multi-well steam stimulation technology which depends on injecting steam into a group of wells and creating a uniform temperature field is useful, as steam channeling caused by longitudinal heterogeneity in the tight oil reservoir and repetitive steam injection may be overcome. Mechanical interval selection technology and vacuum heat insulation pipe are recommended to obtain steam of appropriate volumes. Various high temperature frothers and gel particle plugging agents shall be applied to adjust the steam injection and production profile, improving the sweep efficiency. Liquefied carbon dioxide and other cleanup additives may be injected before steam as more water comes out and remaining oil keeps farther away from the borehole after repetitive steam huff and puff. Fracturing and sand exclusion may be achieved at the same time by squeezing special resins into formation while fracturing. Sand may be controlled by artificial boreholes, optimized liners and flushing foams. Series of drilling and production technologies have been optimized, therefore the average sweep efficiency and recovery rate of single wells in the group were improved by 12.52% and 13.23% respectively.
Conventional steam stimulation used to be adopted by scale in Block CH, while the daily production rate began dramatically decreasing after 4 to 5 rounds of steam injection. The integration of multi-well steam stimulation technology, mechanical interval selection technology, vacuum heat insulation pipe running technique and optimization of chemicals and gases improves heat utilization and sweep efficiency. While the optimized drilling and completion technology improved the quality of horizontal wells.
Saikia, Pabitra (Kuwait Oil Company) | Shanat, Faisal (Kuwait Oil Company) | Ahmed, Khalid (Kuwait Oil Company) | Choudhary, Pradeep (Kuwait Oil Company) | Ferdous, Hasan (Kuwait Oil Company) | Ahmed, Fatma (Kuwait Oil Company) | Fournier, Frédérique (Beicip-Franlab)
Heterogeneous lithofacies distribution resulting into a complex rock-type model in shallow unconsolidated reservoir has a direct role on fluid distribution and trapping mechanisms. A systematic evaluation of these rock-types is necessary for proper reservoir characterization and modeling. In reality, the lithofacies leading to rock-types act as the building blocks to construct a realistic static model, which serves in the understanding of the dynamic behavior of the reservoir.
During this study, 202 wells were selected across the field to capture the vertical and lateral heterogeneity of the reservoir, out of which 93 wells have cores. During a first step, a lithofacies prediction model was created from the core sedimentological description, X-Ray Diffraction (XRD), and wireline logs (raw and mineralogical logs) using probabilistic classification schemes. In a second step, petrophysical data like Routine Core Analysis (RCAL), Mercury Injection Capillary Pressure (MICP), were included to build rock-types associated with the different lithofacies. This integration workflow has resulted in a robust lithofacies and rock-type model consisting of nine lithofacies and five rock-types respectively. It was also noticed that silty non-pay and marginal pay reservoir have inadequate MICP data. Subsequently, two wells were selected and MICP data will be collected for improved and more confident modelling in future.
This model assists to predict lithofacies and rock-types in un-cored wells provided a set of relevant logs are available. The integrated workflow ensures that the lithofacies and rock-types determined at the wells are consistent all over the study area.
The identified lithofacies and rock-types will add great value in building a realistic reservoir static model since they are able to explain the fluid distribution pattern and the concept of barriers and baffles in the reservoir. This will also assist in optimized perforation and completion plans for the reservoir. Ultimately, the input data are readily available for future field-intensive reservoir characterization.
Temizel, Cenk (Aera Energy) | Kirmaci, Harun (Freelance Consultant) | Inceisci, Turgay (Turkish Petroleum) | Wijaya, Zein (HESS) | Balaji, Karthik (University of Southern California) | Suhag, Anuj (University of Southern California) | Ranjith, Rahul (University of Southern California) | Al-Otaibi, Basel (Kuwait Oil Company) | Al-Kouh, Ahmad (Middle East Oilfield Services) | Zhu, Ying (University of Southern California) | Yegin, Cengiz (Texas A&M University)
Diatomites are high-porosity, low-permeability reservoirs with elastoplastic properties and high geo-mechanical responsiveness. They have a great potential for oil recovery despite these drawbacks. Withdrawal of fluids from the reservoir rock leads to subsidence causing compaction and shear stresses. This disturbed stress distribution results in well failures that causes loss of millions of dollars. Successful maintenance of pressure support through optimum injection/production is key to preventing subsidence to mitigate the risk of well failure and achieve better sweep efficiency for recovery.
There have been different approaches to tackle subsidence and well failures in diatomites, including the use of ‘backpressure method’, coupled with a neural network to optimize injection-production to ‘balance’ the rock in terms of stress-distribution and thus decrease well failure due to shearing. However, using such methods may mask other problems the well is experiencing including several mechanical issues that influence production. Another existing approach, satellite-imaging (InSAR) cannot be used to take real-time actions that is crucial in diatomites.
Surface tiltmeter data is collected to undertsand the relationship between injection/production and resulting surface deformation, which also provides information about well-to-well connectivity. A neural network-based approach is followed to determine the nonlinear relationship between surface subsidence/dilation and injection-production. This is then used to build an objective function that works to minimize the differences between well-to-well subsidence/dilation measured by the tiltmeters, by adjusting injection-production for the wells.
In this paper, a method that harnesses real-time surface tiltmeter data to adjust injection-production distribution in diatomites to decrease well failures is used beyond the existing applications of surface tiltmeter, for instance, in the areas of detection of early steam breach to surface in steam operations and fracture orientation. This method also provides real-time data for robust reservoir management of such reservoirs where satellite imaging is not effective.
Use of vacuum-insulated tubing (VIT) in thermal (typically steam injection) wellbores dates back to at least the 1980s but, due to high cost and limited availability, its use until recently had been limited. While it has the potential to significantly reduce heat losses to overburden, thereby improving well operating economics, the correct application of VIT can be more of an art rather than science given the factors that impact its performance.
These include understanding how VIT is manufactured and what design elements influence good long-term performance, what quality assurance is used during manufacture and on the finished product, how to confirm actual k-factor (insulation) values on delivered product in lieu of advertised values, and how to verify true performance once the VIT is installed in a well.
Recent new global sources of VIT have provided additional product choices for operators, as well as more competitive pricing, allowing VIT to be more broadly considered in projects where downhole heat losses must be actively managed to achieve the recovery performance desired. Calculation of heat loss reduction can be done with several different programs, but careful attention must be paid to the way the computer model is built to ensure results reflect actual, expected, field conditions.
World class oil and gas operating companies apply supply chain management to minimize the risks of investment costs overrun, delays and future higher operating costs of field development projects. Supply chain is a cross-functional approach to plan the flow of goods and services required by a project, based on its front end loading (FEL) specifications, in order to meet business objectives with a successful execution and total satisfaction of the final customers. This paper presents lessons learnt from modeling the supply chain of a steam-based thermal enhanced oil recovery (EOR) heavy oil field development project in Kuwait.
A critical building block of a supply chain model is the supply-demand matrix, which is prepared using information about the needs of the steam-based thermal EOR assets (natural and physical) and identification of requirements organized in segments, around capital, technology or manpower categories. A preliminary identification was made about local capabilities to meet these requirements.
A work breakdown structure from the front-end engineering design was used to generate a supply-demand matrix with materials including special needs such as energy, water and logistics. The model allows the identification of critical requirements and the information to design alternate options to reduce the risk of lack of supply. One practical result is a map with all required suppliers classified according to the type of goods or services, and the specifications or scope of work for selecting a contracting strategy.
Supply chain modeling provides a best practice to meet the demand of goods and services of complex heavy oil steam-based thermal enhanced oil recovery projects. It would help to guide the process of building capabilities in Kuwait oil industry for this type of recovery technologies, which will play a critical role in long-term business strategy.
AlSofi, Abdulkareem M (Saudi Aramco) | Wang, Jinxun (Saudi Aramco) | AlBoqmi, Abdullah M (Saudi Aramco) | AlOtaibi, Mohammad B (Saudi Aramco) | Ayirala, Subhash C (Saudi Aramco) | AlYousef, Ali A (Saudi Aramco)
The synergy between various enhanced oil recovery (EOR) processes has always been raised as a potential optimization route for achieving a more economic and effective EOR application. In this study, we investigate the possible synergy between polymer and SmartWater flooding. While the potential for such synergy has been suggested and researched in the literature, we investigate this possibility in a more realistic framework—part of the development of an EOR portfolio for a slightly viscous Arabian Heavy reservoir. In this work, we study the possible synergy between SmartWater and polymer flooding by performing rheological, electrokinetic (Zeta) potential, contact angle and displacement experiments.
Rheological tests as expected demonstrated the possibility of achieving the same target viscosity at lower polymer concentrations. With SmartWater, the polymer concentration required to achieve a target viscosity of 11 mPa.s was found to be one-third lower than that with normal high salinity injection water. Electrokinetic potential and contact angle results demonstrated that polymer presence has a negligible to slight yet favorable impact on wettability alteration induced by SmartWater. On synthetic calcite surfaces, polymer showed negligible impact while on rock surfaces polymer resulted in a further reduction in contact angle beyond that obtained with SmartWater.
Coreflooding experiments conducted at reservoir conditions with finite SmartWater/polymer slugs demonstrated the enhanced performance of SmartWater/polymer compared to either of these individual processes besides yielding comparable performance to surfactant/polymer flooding. A combined SmartWater/polymer process was able to recover substantial additional oil (6.5 to 9.9% OOIC) above that obtained with either of the two processes when applied independently. Ultimate recoveries from the application of SmartWater/polymer (70% OOIC) were quite comparable to – actually slightly higher than – that of surfactant/polymer (67% OOIC). However, in terms of the remaining oil in core (ROIC) post polymer flooding, both processes (SmartWater/polymer and surfactant/polymer) exhibited quite similar incremental recoveries of 20.6 and 20.5% OOIC, respectively.
The results of this work clearly demonstrated the potential synergy between SmartWater and polymer flooding – beyond that of the well-established polymer viscosity enhancement – for a realistic scenario. The additive effect of SmartWater was successfully shown to combine with polymer to increase oil recovery, in addition to lowering the polymer concentration. Therefore, this favorable synergy will reduce chemical consumption and costs and improve recovery and returns to enhance EOR project economics for the slightly viscous Arabian heavy oil reservoir considered in this study.
Gonzalez, S. (Kuwait Oil Company) | Al-Khamees, Waleed (Kuwait Oil Company) | Abdalla, A. W (Kuwait Oil Company) | Rajab, S. Y. (Kuwait Oil Company) | Fadul, I. (Schlumberger) | Jama, A. (Schlumberger) | Hamlaoui, A. (Schlumberger)
The Large Scale Steam Flood Pilot with two patterns in South Ratqa Field (Heavy Oil – North Kuwait) is considered the first of its kind in KOC and a major milestone for North Kuwait (NK) Heavy Oil Development program. The pilot program is crucial for NK Heavy Oil development plans as it will allow the evaluation of the Lower Fars Heavy Oil reservoir at close spacing, and it will assess the implication of the selected recovery process for South Ratqa (SR) field operations and project economics. In addition, the project will enable NK to: Optimised production of Heavy Oil reserve through Steam Flood Assess well completion integrity and optimum A/L type Identify Cost optimization opportunities for Heavy Oil phased development
Optimised production of Heavy Oil reserve through Steam Flood
Assess well completion integrity and optimum A/L type
Identify Cost optimization opportunities for Heavy Oil phased development
The two patterns test different schemes, one for the evaluation of 10-Acre spacing with the second for evaluation of 5-Acre spacing with inverted five spot configurations. The 10-Acre pattern consists of 13 wells (Producer/Injector) plus 7 observation wells; the 5-Acre pattern consists of 13 wells (Producer/Injector) plus 4 observation wells. All observation wells are equipped with Distributed Temperature Sensing (DTS) systems. Furthermore, for the first time in KOC, all wells are equipped with the thermal wellhead stack up to allow operations while injecting or prodcing. This will greatly save time, rig cost and minimize workover interventions.
Production and Reservoir engineers frequently use allocated volumes to estimate current production volumes from wells based on frequent well test data or theoretical calculations using well and reservoir characteristics.
The KOC Heavy Oil asset deployed a production data management system (PDMS) from early days of Large Steam Thermal Pilot North (LSTPN) production to establish a scalable and reliable workprocess among the organisation. The production and operations data management system manages steam injection, soaking and the production phases through data collection, quality control validation and production back allocation as well as shortfall analysis for planned and unplanned downtime events.
The new system provides main checks for the steam injection and emulsion production streams, track gathering systems functionality through time, derive the allocation networks, and produce internal and external reports.
The field study is in northern part of Kuwait targeting heavy oil formation, known to be shallow unconventional oil reservoir. It is heterogeneous shallow sandstone reservoir (500ft TVD) with low maturity oil, has low natural pressure, and poorly consolidated. Mud losses known to be the main risk of horizontal drilling in shallow heavy oil environment and the heterogeneous including continuity of the sand are also challenging for geo-steering team in order to place the well in the optimum position. Seismic is not available, however due to high offset well density a good correlation map has been produced. We are using formation tops from offset wells to delineate the continuity of the sand and trend of the structure dipping, we called it as shooting point method, which is assuming the trend of the structure from one offset well to another nearby offset well. The resistivity contrast will be expected to give us around 9 ft depth of detection (DOD) for our Azitrak resistivity tool based on Picasso plot. We made some scenarios for exiting the reservoir and it showed us some early warning 80ft to 180 ft prior to exit the reservoir. We use Autotrak, Azitrak dan Litotrak formation evaluation and density imaging tool to geo-steer and optimally place the wellbore inside 1B sandstone. The expectation of drilling the lateral was below 1000ft MD due to wellbore stability issue. From the correlation of available offset well it is clearly seen, there are two sand bodies in heavy oil target sand. The thickness is around 30-40 ft TVD and the structure was expected to be flat or a little bit dipping down. The well was landed in the middle of 1B, based on correlation of actual landing point log data to the nearest offset wells. Distance to bed boundary (D2B) showed local conductive layer from bottom since drilling the lateral section, which was not the response of base of 1B sand. So it was recommended to go down in stratigraphy in order to place the trajectory at the bottom part of 1B sand. In order to minimize wellbore stability issue along the lateral section, Bakerhughes recommended to maintain consistent faster ROP (80-100ft/hr) and effective hole cleaning. In the middle of lateral section of well B (1750ft MD) the well trajectory was inverted for the optimum production purposes to total depth (2250ft MD). Total lateral length achieved is 1116ft MD which covers 100% of the lateral length. Shooting point method in defining the rough structure trend from one well to another well was effectively applicative in the field, where current structure after drilling the lateral section is almost flat or slightly dipping down same as predicted before.
Co-injection of solvents with steam increases the oil recovery factor and reduces significantly the environmental impact of steam injection processes. Nevertheless, the quality of the extracted bitumen is important to evaluate the process performance which is affected by the solvent-bitumen interaction. This interaction might lead to emulsion formation and asphaltene precipitation. These unfavorable flow assurance problems are associated with the behavior of asphaltenes in solvent-steam processes. Thus, it is important to observe the factors affecting the interfacial forces among asphaltenes-solvents-water prior to any field application. This work investigates the fundamental aspects of the solvent-bitumen interaction during solvent-steam injection processes. A Canadian bitumen was studied. The role of individual saturates, aromatics, resins, and asphaltenes (SARA) fractions of bitumen on solvent-steam process performance was examined both at liquid and vapor water conditions. The behavior of asphaltenes was investigated through systematic microscopic analyses with the absence and presence of reservoir rock. Also, the asphaltenes behavior after toluene (asphaltene soluble aromatic hydrocarbon) and n-pentane (asphaltene insoluble aliphatic hydrocarbon) addition was observed under the microscope. While toluene completely dissolves asphaltenes immediately, n-pentane leads to asphaltenes precipitation with bigger clusters. After these control experiments, the same tests were carried out with the addition of saturates and/or aromatics fractions of crude oil to the asphaltenes fraction. It showed that saturates lead to aggregation of asphaltene clusters at a higher rate than n-pentane, while aromatics dissolve the asphaltenes at a lower rate than toluene. Hence, it was found that the asphaltenes precipitating power of saturates is higher than n-pentane. However, results reveal that asphaltenes mainly interact with water and aromatics fraction of bitumen. The water-asphaltene interaction causes the emulsion formation and the aromatics-clay interaction is responsible for clay migration and higher amount of asphaltene precipitation. The results of this study help us to understand the factors acting upon displacement of bitumen during solvent-steam processes.
Kuwait Oil Company (KOC) is planning to adopt thermal method for the recovery of heavy oil in its north Kuwait heavy oil reservoir. However there are growing concern of salts precipitation and scaling deposits, especially magnesium hydroxide (Mg(OH)2) in the targeted reservoirs due to the potential reaction of alkaline steam water mixture with the reservoir waters which contain significant concentration of magnesium, barium and other components. A comprehensive compatibility study was carried out using laboratory test and computer scaling predictions of scaling tendencies of the fluids as follows: Alkaline steam boiler feed water (SBFW) with the Lower Fars (LF) formation water Heavy oil Produced water (formation + condensed water) from the thermal wells) with the Tayarat formation water
Alkaline steam boiler feed water (SBFW) with the Lower Fars (LF) formation water
Heavy oil Produced water (formation + condensed water) from the thermal wells) with the Tayarat formation water
This paper presents the results of computer scaling study performed using ScaleChem simulation software and laboratory examination of water compatibility using the Jar test analysis for mixing alkaline steam boiler water (SBFW) with the Lower Fars formation water (LFW).
The main objectives of this study were as follows: To analyze and characterize the SBFW and LFW To perform computer scale compatibility study to predict type and masses of scale that could be generated as a result of mixing pH adjusted steam water with the LF water. To predict scaling tendency of individual waters at defined temperature and pressure conditions To check compatibility of these waters using laboratory Jar tests
To analyze and characterize the SBFW and LFW
To perform computer scale compatibility study to predict type and masses of scale that could be generated as a result of mixing pH adjusted steam water with the LF water.
To predict scaling tendency of individual waters at defined temperature and pressure conditions
To check compatibility of these waters using laboratory Jar tests
The type of scale and the location in which it is predicted to occur are important factors when considering the risk of scale formation. Scales such as calcium carbonate (CaCO3) can be removed relatively easily with the appropriate chemical treatment. Alternatively, scales such as barium sulphate (BaSO4) are much more resistant to chemical treatments and can require more specialized products. These chemical treatments present significant health and environmental risks, and considerable additional expense. Results indicated that both calcium sulphate (CaSO4) and Mg(OH)2 are predicted to form in the boiler and the amounts of solid phase is computed to exceed 3,000 mg/l, depending on the inlet pH. At lower pH, in the mixing calculation for the reservoir, BaSO4 is dominant scale. At higher pH, several scales are computed to exist.