Majority of oil wells operated by Petroleum Development Oman (PDO) are produced by beam-pumps (BP). Average water cut in a number of fields in South of Oman reaches 95%. Increasing water production overloads processing facilities leading to handling and disposal constrains requiring wells to be shut-in.
BP completions are not surveillance friendly making production logging to identify water entry for optimization (water shut-off) a challenge. The current technique to acquire production logs requires recompletion to dual-string completion to allow logging: BP short-string and surveillance conduit long-string. This is resource intensive, high cost, restricts production and limited to 9-5/8in. cased wells. Moreover, new wells are completed with dual 9-5/8in. x 7in. casing for well life-cycle integrity management.
A novel solution was developed and part-funded by PDO consisting of a jet-pump (JP), 1in. inside 2in. concentric-coiled tubing (CCT) strings, power cable and production logging tools (PLT). This cost-effective real-time surveillance technique will facilitate routine production logging in BP wells, significantly reducing well intervention time and cost (50% reduction) as only the rod string is retrieved by light-hoist in preparation for logging.
Wells completed with dual-string completions, which have previously been production logged were selected for field trial. These existing logs were used as a baseline for new log comparison. The technique was successfully deployed in a 3 well field trial campaign for the first time in southern oilfields (industry first). The new production logs compared very well to existing logs (same water signature observed), proving the techniques robustness to identify water entry in different production environments.
We preset advantages of the new technique over conventional, candidate selection, logging tool options, interpretation methodology, field trial results and comparison logs. This new system is being deployed across PDO and is applicable to other fields being produced by BP, progressing-cavity pump (PCP) or electrical submersible pump (ESP) to identify water entry for production enhancement or reservoir monitoring.
The prediction of asphaltene precipitation is an important topic in petroleum industry. Reliable evaluation of the asphaltene stability requires representative samples and measurement using special high pressure equipment. Moreover, development project may involve many reservoirs with many different fluids. Even inside of a connected reservoir, the quality of the oil and the asphaltene can vary through a large scale and the investigation of each fluid in the representative conditions become very expensive and often impossible.
Many fast screening methods have been proposed so far. The De Boer's diagram is one of the most useful methods. However, it takes into account only the properties of the hydrocarbon phase without any investigation on the asphaltene fraction : this method gives always pessimistic prediction of the risk of asphaltene precipitation. Other methods, colloidal instability index for example, are not consistent enough to be used for flow assurance issue.
Based on some relevant solubility properties of the asphaltene fractions, a new and easy way for screening asphaltene instability is proposed. Using PVT properties of the live oil and an easy asphaltene characterization procedure, this method allow limiting advanced investigation only to fluids which present a real risk of precipitation. The asphaltene characterization can be performed on dead oil samples.
If a precipitation risk is stated, additional tests, performed on pressurized representative samples or taking into account reorganization of asphaltenes from different fluids, will help to define the severity of the risk. For mitigation, a test set-up has been developed: it allows evaluating the efficiency of chemical additives to prevent plugging under flow conditions of fluids above the asphaltene precipitation threshold. Depending on the crude oil, the severity of the precipitation conditions, and the nature of the additive, the blocking of the capillary tube can be delayed or prevented.
Hadibeik, Hamid (UT Austin) | Proett, Mark (Halliburton) | Chen, Dingding (Halliburton) | Eyuboglu, Sami (Halliburton) | Torres-Verdin, Carlos (UT Austin) | Sepehrnoori, Kamy (University of Texas at Austin)
Testing in tight formations and unconventional reservoirs poses significant challenges when determining reservoir pressure. The primary difficulty in testing a low mobility formation is that a conventional pressure transient test cannot be applied because the buildup time required for pressure stability after a typical drawdown is excessively long. To reduce testing time, a new automated pulse test method has been developed.
The new pulse test method consists of a drawdown or injection followed by a short stabilization period. Then depending on the buildup response, a new drawdown or injection is performed followed by a short buildup. This sequence is repeated until the desired buildup stabilization is achieved and then a final extended shut-in period is used for analysis of formation properties such as pressure and mobility. The pressure stabilization time can be further reduced by implementing an adaptive pressure feedback in the system.
This new method uses sequential pressure responses and automated pressure pulses. The analysis of the final pressure yields a measurement in 0.5% range of the initial formation pressure while decreasing the wait time by a factor of 10 for a packer-type formation tester. Furthermore, the pressure measurements are analyzed to obtain reservoir permeability and storage.
The new method was tested on synthetic reservoir models and a field study. These demonstrated that the method permits a rapid appraisal of pressure measurement in comparison with conventional testing. Moreover, the implemented feedback system mitigates the supercharge effect.
Alzaid, Mustafa R. (Saudi Aramco) | Al-Ghazal, Mohammed A. (Saudi Aramco) | Al-Driweesh, Saad (Saudi Aramco) | Al-Ghurairi, Fadel (Saudi Aramco) | Vielma, Jose (Halliburton) | Chacon, Alejandro (Halliburton) | Noguera, Jose (Halliburton)
In recent years, high-pressure/high temperature (HPHT) sour gas producers in Saudi Arabia, completed with two or more open hole laterals have faced several operational challenges, specifically for well intervention and stimulation procedures. Several lessons learned throughout the timeline of the operations and the procedures have evolved to optimize and enhance the results. Drilling and completing open hole multilateral gas wells in carbonate reservoirs is a common practice in Saudi Arabia to maximize reservoir contact and increase the recovery of reserves. The majority of these wells require coiled tubing (CT) conveyed acid stimulations to remove drilling damage and enhance productivity after the drilling process.
The challenging conditions encountered during the aforementioned CT interventions include: extended open hole horizontal sections with large hole diameters affecting the ability of reaching the deepest zones of interest; pumping 26% inhibited hydrochloric (HCl) acid for extended periods of time at high temperature with extremely high H2S and CO2 content, generating a very corrosive environment for all tubulars involved in the operation; wellbore instability issues inducing obstructions that prevent the accessibility to open hole sections; accessibility of alternate laterals, especially after the first lateral has been stimulated; optimum rate and pressure to achieve the desired pressure drop across hydrajetting nozzles; and natural fractured reservoirs that promote fluid losses affecting the optimum fluid placement control.
The inclusion of friction reducers for CT extended reach applications, combined with the introduction of larger outer diameter (OD) CT, have improved the access to the zones of interest. The redesign of the isolation sleeve for the jetting tool has reduced the number of required trips when obstructions have been encountered, including the improved use of steering tools to access target laterals. Further laboratory analysis, specific to the HPHT sour conditions of these wells, has been performed to minimize corrosion in the completion and the CT, and to optimize the pumping schedules to target the pay zone. This paper provides details about field experiences and lessons learned with this type of stimulation, and describes challenges faced and the engineering solutions developed to overcome them.
Sarapardeh, A. (Sharif University of Technology) | Kiasari, H. Hashemi (Amir-Kabir University of Technology) | Alizadeh, N. (Schlumberger) | Mighani, S. (University of Oklahoma) | Kamari, A. (Omidiyeh Branch of Islamic Azad University)
Steam injection process has been considered for a long time as an effective method to exploit heavy oil resources. Over the last decades, Steam Assisted Gravity Drainage (SAGD) has been proved as one of the best steam injection methods for recovery of unconventional oil resources. Recently, Fast-SAGD, a modification of the SAGD process, makes use of additional single horizontal wells alongside the SAGD well pair to expand the steam chamber laterally. This method uses fewer wells and reduces the operational cost compared to a SAGD operation requiring paired parallel wells one above the other. The efficiency of this new method in naturally fractured reservoir is not well understood. Furthermore, how operational parameters could affect the efficiency of this method is a topic of debate. In this study, Fast-SAGD is compared through numerical reservoir simulations with standard SAGD in an Iranian naturally fractured heavy oil reservoir and additionally some operational parameters including initiating time of steam injection in offset well, number of cycles assuming the same total period of steam injection, offset injection pressure, elevation of offset well from the bottom of reservoir and vertical distance of production and injection SAGD well pairs have been evaluated in Fast-SAGD process. The operational parameters have been optimized based on Recovery Factor (RF) and economical points. The results of this study demonstrated the exceptional performance of Fast-SAGD process in naturally fractured reservoirs and the RFand thermal efficiency of Fast SAGD are enhanced tremendously comparsed to SAGD. In addition, the results indicated that the most important parameters that should be optimized before Fast-SAGD is initiating time of steam injection in offset wells. This study reveals improved efficiency and lower extracting costs for heavy oil in naturally fractured reservoirs applying Fast-SAGD process. Also it is indicated that optimization of operational parameters significantly improves Fast-SAGD performance in such reservoirs.
Rajan, S. (Kuwait Oil Company) | Al-Naqi, M. (Kuwait Oil Company) | Al-Humoud, J. (Kuwait Oil Company) | Ameen, A. A. (Kuwait Oil Company) | Al-Qattan, M. N. (Kuwait Oil Company) | Al-Hashash, H. H. (Kuwait Oil Company) | Al-Enizi, N. (Kuwait Oil Company) | Madhavan, S. (Kuwait Oil Company) | Al-Qattan, A. (Kuwait Oil Company) | Brooks, A. D. (AAR Energy)
The Greater Burgan Field is the largest clastic oilfield and the second largest oilfield in the world. First discovered in 1938, and developed from 1946, production to date has relied on primary recovery methods. More recently secondary and enhanced recovery techniques have been investigated and water flood is now at an advanced state of implementation. The first such water flood project is being implemented in the Upper Cretaceous (Cenomanian) Wara Formation, which is one of the main producing reservoirs within the Greater Burgan complex. Here, production has been accompanied by steadily declining reservoir pressure.
The Wara Formation comprises multiple sandstone units deposited in a fluvial-tidal coastal system with a total thickness of approximately 140 - 180 feet. The reservoir exhibits a considerable degree of permeability heterogeneity. Lateral and vertical extent, and the pressure communication between sand bodies is highly complex. Understanding of hydraulic connection and volumetric sweep are therefore one of the key development challenges to address in this complex reservoir.
To avoid costly water disposal and to make best use of available resources the full field waterflood will re-inject produced water. Therefore project planning required an assessment of water injectivity using several water sources and an investigation of the required water quality requirements for the full field water flood.
A peripheral waterflood configuration has been selected for Wara reservoir taking advantage of some 1200 feet of vertical relief between the flanks and crest of the anticlinal structure. Prediction and optimization of this waterflood project required appraisal of structure, pressure, reservoir quality and fluid type in largely undrilled lower flanks areas.
This paper summarizes the pilot waterflood projects, flank appraisal activities and related study work to understand hydraulic connection, reservoir properties, injectivity and reservoir performance. It describes the approach taken and the learning points from each of the activities together with their implications for the full field water flood project.
In the early 2000s, formation pressure while-drilling tools were introduced that can obtain formation pressure data, even in highly deviated wells and extended-reach drilling. In the past two years, this LWD technology has evolved with the addition of downhole fluid sampling and fluid analysis. LWD sampling and testing is now performed in challenging environments that cannot be performed with wireline tools such as horizontal or highly deviated wells. The limitations of wireline deployment in these wells are because of the cumulative frictional resistance of the wireline, the toolstring components and the borehole where it is run. Although several technologies exist to mitigate the risks, such as fly wheels, wireline tractors or pipe-conveyed options, operators prefer to eliminate the risks and costs associated with them by utilizing LWD technology.
The first part of this paper describes the new sampling and testing service that was designed for the LWD environment. The service has several closed-loop control systems for pressure testing, mobility determination and pumping during sampling and cleanup operations. In-situ fluid analysis is achieved with sensors that measure optical refractive index, sound speed, density and viscosity. Downhole fluid samples are retrieved with single-phase tank technology.
The second part of this paper details case studies of field tests that were performed for a major operator in Trinidad and an IOC in the Netherlands. In Trinidad, the service successfully performed pressure testing, real-time fluid analysis and recovered three single-phase samples while drilling a 300ft section at a 70° deviation. On a dedicated logging run in the Netherlands, the service first accurately took 25 formation pressure points and clearly identified three distinct gradients. The customer targeted four zones of interest and acquired 11 samples: six single-phase samples in the oil zone, three single- phase samples in the water zone and three single-phase samples in the gas zone. The pressure testing and sampling was executed in a 1,307 m tangent section at a 73° inclination. The service was utilized to determine the presence of moveable fluids in the reservoir of a horizontal development well for a customer in Norway. The tool was positioned at a sampling station with a mobility of 1.8 mD/cP; after nearly five hours of pumpout at that station, it successfully acquired the first sample, and after another four hours at the same station, the tool acquired the second sample.
In both cases, the LWD sampling and testing service was chosen over wireline to mitigate the risks of sticking during the sampling and pressure testing operation. These field tests demonstrated that the LWD service is capable of taking wireline-quality measurements in extremely challenging borehole environments.
Monte Carlo simulations demonstrate that probabilistic models of hydrocarbon volumes should correlate the degree of porosity uncertainty to the productive volume of the reservoir. Assessments that fail to model the relationship between productive volume and porosity uncertainty may create unrealistic resource estimates and valuations.
The findings are applicable to conventional exploration prospects with significant uncertainty of productive reservoir volume, and to unconventional resource developments with high lateral variation in reservoir quality.
Probabilistic models of hydrocarbon volume include an estimate of porosity, defined by a probability density function such as a normal or lognormal distribution. The distribution models the uncertainty around the "average?? porosity within the field. If a field is small, the productive volume represents a limited sampling of the reservoir. There is a possibility that the average porosity within the productive reservoir may be very high or very low. If the field is large, there is a greater chance that a high porosity in one portion of the field will be offset by a small porosity in another portion of the field, resulting in a narrow range of uncertainty around the average porosity. Probabilistic models that do not decrease the porosity range as reservoir volume increases may generate results in which a high porosity is applied to a large reservoir volume, resulting in resource volumes and economic valuations that are unrealistically high.
The solution lies in the use of multiple-segment models. If each segment represents a stratigraphic layer, or a portion of the potential productive area, and each segment is assigned the wide range of porosity appropriate for a small field, then increasing the number of productive segments will decrease the range of overall average porosity.
This paper clarifies the definition of porosity uncertainty in probabilistic models, reveals a relationship between porosity uncertainty and reservoir volume, and presents a method that will result in more realistic resource estimates and valuations.
Drilling and completing reservoirs without inducing measureable skin damage is rare. Frequently, drilling fluids impact a reservoir's flow potential while drilling as the rock matrix is invaded by solids and chemicals designed to enhance drilling performance. Drilling fluid can also cause formation damage if they are not properly removed during the displacement phase. hese solids can migrate to the perforating zone and cause damage. Completion fluid designs governed by density for well
control also often contribute to skin damage. Hydrocarbon flow may be impeded by damage caused by residual drilling debris or incompatible completion and workover fluids, in-situ emulsions, water block, organic deposition, or oily residue.
Specialized surfactant systems have been developed to remediate near-wellbore damage caused by drilling and completion fluids, and damage induced by failed remediation attempts. The properties of these treatment systems include their ability to
solubilize oil and, due to a significant reduction in interfacial tension between the organic and aqueous phases, effectively diffuse through the damaged zone to free up flow-resistant obstructions. The inherent properties of these systems make them
ideal for removing induced formation damage as well as an excellent option for displacing synthetic or oil-based mud (S/OBM) from casing prior to the completion phase. In open-hole (OH) completions, specialized surfactant designs have proven very effective in removing S/OBM filter cake damage. In cased-hole (CH) completions, they have demonstrated a high degree of efficiency to clean damaged perforations.
This paper presents a technical overview of surfactant systems for OH and CH remediation operations. The testing to qualify these fluids for the removal of damage and field results are presented that show the efficacy of these specialized surfactant systems to remove damage caused by OBM filter cakes and other oily debris to improve hydrocarbon recovery while addressing the operational challenges associated with these jobs.
Fuwei, Zhong (Daqing Oilfield Production Technology Institute) | Dekui, Xu (Daqing Oilfield Co. Ltd.) | Xiaohui, Han (Daqing Oilfield Production Technology Institute) | Xiaoyu, Xu (Daqing Oilfield Production Technology Institute) | Zhongchao, Lin (Daqing Oilfield Production Technology Institute) | Yuan, Gao (Daqing Oilfield Limited Company) | Wenlin, Xu (Daqing Oilfield Production Technology Institute) | Xiaojing, Zhang (Daqing Oilfield Production Technology Institute) | Fei, Gao (Daqing Oilfield Production Technology Institute) | Rongxi, Li (Daqing Oilfield Limited Company)
The Block 3/7 of Sudan Oilfield has been in the period of high water production. The water cut of many wells is more than 80%, and still rising. Besides, there are many sandy wells in this area. In order to reduce the water cut,the conventional technique involves two string trips—water detection primarily, and then water shutoff treatment according to the result of testing. Obviously, high cost and low efficiency restrict its application. Therefore,based on the conventional technique, a new integrated technique for servo adjustable water detection and water shutoff has been researched by Daqing Oilfield Limited Company, which is mainly made up of drillable packers to divide layers,intelligent controlled piezoelectric valves, inserted seal sections and releasing subs. With the integrated technique, dynamic adjustment and water shutoff treatment can be achieved at any layer without pulling the string upward or downward. Applying casing pressure signals can open the appointed position's valve when detecting water, then get its single layer's production, meanwhile record and test on the ground to confirm this layer's production and water cut. Applying casing pressure signals closes the appointed position valve after testing. Repeating the above steps can get all the layers water production and water cut. According to the result of water detection test, open the intelligent controlled piezoelectric valves of the lower water cut layers to stabilize the oil production.
This new technique has been successfully applied to 8 wells in the Block 3/7 of Sudan Oilfield, which features low cost and high efficiency. It could meet the requirements of water detection and water shutoff for the remaining 30 wells of high water production. Similarly, it could apply to many wells of high water production in Daqing Oilfield.