Vledder, Paul (Syria Shell) | Gonzalez, Ivan Ernesto (Syria Shell & AFPC) | Carrera Fonseca, Julio Cesar (Al Furat Petroleum Company) | Wells, Terence (Al Furat Petroleum Company) | Ligthelm, Dick Jacob (Shell Intl. E&P BV)
Low salinity water injection is an emerging EOR technology, applicable to mixed-to-oil-wet sandstone reservoirs. Flooding with low salinity water causes desorption of petroleum heavy ends from the clays present on the pore wall, resulting in a more waterwet rock surface, a lower remaining oil saturation and higher oil recovery.
A secondary flood application is discussed in the Omar field in Syria showing a change of wettability from oil wet to a water-wet system. This change in wettability is supported by the observation of dual steps in watercut development. In between the two steps the watercut was constant. This behaviour is a known indicator of changing wettability. Moreover, direct connate water banking measurements confirm the change. The field observations are supported by spontaneous imbibition experiments in core material and a single well Log-Inject-Log test in an analogue field.
From the field observations, the change in wettability is estimated to be nearly complete, leading to an associated incremental recovery of 10-15% of the Stock Tank Oil Initialy In Place (STOIIP).
The significance of this work is that this is one of the very few documented proofs of concept on a reservoir scale. Work is ongoing to prove this concept in a tertiary flood as well.
High Pressure Air Injection (HPAI) is a potentially attractive enhanced recovery method for deep, high-pressure light oil reservoirs. The clear advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas is its availability at any location. Although, the process has successfully been applied in the Williston Basin for more than two decades, the potential risks associated with the presence of oxygen in air are a significant hurdle for implementation in other locations.
Thermal simulations that include combustion are required to quantify the incremental oil, the oxygen consumption and resulting oxygen distribution from the application of HPAI in a given field. Once such a simulation model is available, it can be used to optimize the injection strategy: strategies that have a good incremental recovery while reducing the amount of gas injected are key to a successful project. The injection rate is bounded by a technical lower limit and an economic upper limit: there is a minimum rate required to maintain the combustion and high rates require larger compressors that are more expensive.
This paper focuses on the optimization of the injection strategy for HPAI in a 3D model with realistic geological features. Numerical simulations with a thermal model that includes combustion were conducted for continuous versus alternating air injection. A critical assumption for alternating air injection in that the remaining oil spontaneously re-ignites.
This study shows that water alternating air injection has a great potential to improve HPAI projects: project life can be extended and incremental recovery is improved when compared with continuous air injection. In addition, the variation in distribution of oxygen between different cycles is presented. This also illustrates that the numerical model can be used as an oxygen management tool. The effects of alternating air injection are comparable to the effects of alternating gas injection: the saturation in the swept areas changes due to the alternating (re-) invasion of gas, oil and water.
This paper illustrates that modeling oxygen consumption is essential for the evaluation of potential risks and optimization of the HPAI process.
NEAG1 is one of Bapetco fields located in the eastern part of the Western Desert, close to Qarun field. Special Core analysis has been used in an integrated way to optimize parameters used in Static and Dynamic reservoir models. The methodology of selecting the adequate core plugs was an integrated work of PP, PG and RE engineers to ensure optimal selection of samples representative for the reservoir. Routine Core analysis and core photos, logs, SEM were used in the selection procedures.
The results are being integrated into the Static and Dynamic model and they show an improved prediction of reservoir properties.
Moradi, Sara (Schlumberger) | Zonzee, Peter (Al Furat Petroleum Company) | Jain, Bipin (Schlumberger) | Elarda, Hussein (Schlumberger) | Sandhu, Depinder Preet Singh (Schlumberger Oilfield Services) | Salazar, Jose (Schlumberger)
Cementing long zones with a single slurry system is a very challenging problem that has been known in the industry for many years. The main difficulty is related to the large temperature differential between the bottom and the top of the long cement column. The cement slurry is typically designed to have a thickening time to allow placement at the bottom hole circulating temperature. However, the same slurry when exposed to the much lower temperature that exist at the top of the cement column may not set for several days. This can lead to long waiting on cement resulting in rig non productive time or in certain cases can lead to well integrity problems.
Another known problem in the industry is setting of cement plugs in an environment where the bottom hole temperature is not well known. This scenario may exist while setting unplanned kickoff plugs or plug and abandonment of wells. The thickening time of slurries retarded with conventional additives are sensitive to temperature and therefore uncertainties in bottom hole temperature may lead to excessive setting time or premature setting, both of which can be costly.
A new generation of engineered cement set control (ECSC) additive has been developed to resolve the problems mentioned above. The ECSC additive provides thickening times that are almost independent of temperature thus allowing efficient and reliable cementing of long cement columns, where there is a large temperature differential between the top and the bottom. The ECSC additive will also minimize setting problems in situations where the bottom hole circulating temperature is not known accurately.
This paper presents the results of a successful field application of the ECSC additive to cement long casing sections in fields in the Middle East. The well designs require the reliable isolation of long casing/liner sections in order to safeguard well integrity and meet well construction objectives.
Field implementation, results including logs from the wells are presented.
Copyright 2005, International Petroleum Technology Conference This paper was prepared for presentation at the International Petroleum Technology Conference held in Doha, Qatar, 21-23 November 2005. This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor Society Committees of IPTC.
This paper presents the application of high-resolution static and dynamic modelling in complex faulted fluviatile sandstone reservoirs. It is based on results of an integrated study of one of AFPCâ€™s fields in the Euphrates Graben, Syria, with the Cretaceous Lower Rutbah and Triassic Mulussa F1 & F2 forming the three main reservoir units. It describes the modelling challenges and the advantages of high-resolution models in reproducing the dynamic reservoir processes as observed from well data. It also shows how a dynamic process-based modelling workflow resulted in history match improvements and higher reliability of predictions. Subsequent field implementation of the project recommendations provided the ultimate validation of the modelling approach and demonstrated the predictive value of the models.
The paper also highlights the added value of 3-phase streamline simulation in full field history matching and improving the understanding of flow paths in the reservoir as a result of the interplay of fluvial channel sands and numerous fault juxtapositions. It compares streamline simulation with the traditional finite difference simulation results and describes the strengths and weaknesses of streamline simulation applied during history matching.
The investigated field has three main reservoir formations, which are the Lower Rutbah (RUL), Mulussa F1 (MUF1) and Mulussa F2 (MUF2), shown in a schematic cross section in Figure 1.
The Mulussa F sequence (MUF) is dominated by fluvial sandstone bodies alternating with flood plain fines and soil horizons. The reservoir quality of sands is good (average net porosity of some 16%, permeabilities ranging from 30 to 1000 mD, average oil saturation of 83%). The Triassic Mulussa is separated from the overlying Cretaceous Lower Rutbah formation by the regional BKL unconformity, which resulted in partial erosion of the formation within the field area, in particular in the western part. Hence the MUF1 varies greatly in thickness over the field, whereas the MUF2 has a layer-cake architecture (at the level of major stratigraphic units). Another key difference between the MUF1 and the MUF2 formations is the N/G ratio, which is high in the MUF2 (50-70%) and low in the MUF1, where it only attains 30%.
Offset VSP data in the Deir Ez Zor area contains significant mode-converted shear wave energy. This allows us to obtain two results: a P-wave and an S-wave OVSP image. The additional information contained in the shear wave image can significantly aid interpretation. There are however differences in character, amplitude and polarity. Interpreted in conjunction with Zoeppritz equation modeling, these can provide information about lithology and fluid content that cannot be extracted from P waves alone.
We now believe, based mainly on evidence from offset VSP data, that part of the noise in our surface seismic consists of mode converted shear waves, rather than P-wave multiples. NMO velocities and AVO anomalies in prestack surface seismic data corresponded with modeled PS responses. Such modeling thus provides a method of identifying suspected PS reflections in the vicinity of wells with OVSP data or full waveform sonic and density logs. Depending on the importance of a particular event, if there is a suspicion that it may be a PS reflection, it will often be justified to obtain OVSP data and to re-evaluate pre-stack surface seismic data.
Water production in a oil field in Syria has increased significantly in recent years. As a result oil production is currently constrained by facilities throughput. PLT surveys combined with a reservoir study on the field showed that some layers still have high hydrocarbon saturation whilst others are already swept by water. Good-quality sands are not properly swept, probably due to poor connectivity in the reservoir. By shutting of the watered-out sands the high oil saturation un-swept sands can contribute to the production. However, no mechanical through tubing technologies are currently available, due to the high expansion ratio, the high differential pressure (up to 3000 psi) and the high temperature of 150 °C.
A new particle-gel has been developed for solving the above-described problem in a cost-effective manner. The particle-gel system is a further development of the previously published gel-cement system. The system may be placed via coiled tubing similar to a cement squeeze. The particles in the system will create a diverting filter cake resulting in a uniform and shallow placement of the gel of typically less than 1 inch. The gel used as make up water of the slurry will be squeezed into the matrix creating a shallow matrix shut off after it is set.Selective perforation of the hydrocarbon zones can re-establish the oil production. Additionally, the shut off zones can be re-opened later in the well's life when artificial lift has been installed.
The system showed superior shut off performance in the laboratory compared to normal cement squeeze techniques. In the first field application the system was tested in vertical oil well with a static bottomhole temperature of 146 °C. A total of 186 meters of perforations were squeezed of with the particle-gel in a single attempt. Post-job PLT data confirmed that the shut off was complete because the sealed zone showed no inflow.
van Eijden, Jip (Shell International Exploration and Production B.V.) | Arkesteijn, Fred (Shell International Exploration and Production B.V.) | Akil, Ihab (Al Furat Petroleum Company) | van Vliet, Jacques (Al Furat Petroleum Company) | van Batenburg, Diederik (Halliburton) | McGinn, Paul (Halliburton)
Water production in the North-east of Syria has increased significantly in recent years. As a result costs per barrel of oil have increased and the field's production is currently constrained by the facilities capacity.
PLT surveys combined with a reservoir study showed that good-quality sands were not properly swept by the water, probably due to poor connectivity in the reservoir. It was anticipated that these un-swept sands could contribute to production if the watered out sands were shut-off.
A newly developed gel-cement has been used to shut-off the watered out sands in a cost-effective manner. The gel-cement system combines the properties of two shut-off techniques:
Cement for mechanically strong perforation shut off.
Gel for excellent matrix shut off.
The gel, used as "mix water" of the cement, will be squeezed into the matrix creating a shallow matrix shut off. The cement will remain in the perforation tunnel as a rigid seal. This system showed superior shut off performance in the laboratory compared to normal cement squeeze techniques. Selective perforation of the hydrocarbon zones will re-establish the oil production. The shut off zones can be re-opened later in the well's life when artificial lift has been installed.
In the first field trial 84 meters of perforations (gross) were squeezed of with the gel-cement in a single attempt. After re-perforation of the top and the middle zone the well produced at a strongly reduced water cut, i.e. 25-33% compared to 60-62% before the treatment, and an increased oil production, i.e. 3000 bopd compared to 1000 bopd before the treatment. The oil production declined to 2000 bopd over a year. The water cut gradually increased over that period to 56%.