Thesis (Ph. D.)--University of Wyoming, 2006. / Title from PDF title page (viewed on Dec. 20, 2007). Includes bibliographical references (p. 208-216).

Thesis (M.S.)--West Virginia University, 2006. / Title from document title page. Document formatted into pages; contains xx, 159 p. : ill. (some col.), map. Includes abstract. Includes bibliographical references (p. 64-65).

Thesis (M.S.)--Brigham Young University. Dept. of Chemical Engineering, 2005. / Includes bibliographical references (p. 159-161).

Several types of transient well testing in Norne field are presented in this thesis. One production well from each segment in Norne field was participated in different type of test. The well test data of all cases were generated from reservoir simulation. It allows flexibility in modifying reservoir model condition to understand different behavior of pressure response. The tests were first started by producing the well at a constant rate for 10 days, and then shutting-in the well for at least 24 hours. The importance of reservoir model grid refinement, determination of reservoir communication across the fault, and the complexity of horizontal well test analysis are the three main discussions in this thesis work.Series of buildup tests at well D-1H in C-Segment were performed to recognize the significance level of Local Grid Refinement (LGR) near the wellbore. There are two sensitivities performed in the reservoir model, extension of LGR area and increase of LGR factor. Based on pressure responses, wider area of LGR affected permeability estimation, while increase of LGR factor impacted the storage capacity calculation. In the next discussions, LGR near the wellbore becomes a standard procedure in generating well test data.The next type of transient well testing performed in Norne field is interference test. This test was executed at well E-3H as an observation well in E-Segment; while well E-1H and E-2H acted as interfering wells in D- and E-Segments respectively. According to pressure and production trends, it can be ensured both interfering wells are located in different segments. A reservoir communication across segments was identified through pressure drop analysis at well E-3H; hence presence of a major fault between segments is not fully sealed.Transient well testing in horizontal well gives a special and more complex analysis compare to vertical well analysis. A buildup test was examined at horizontal well E-4AH in G-Segment to determine vertical and horizontal permeability. Two flow regimes existed during the test, early-time radial flow and intermediate-time linear flow. They were discovered from pressure versus time plot and pressure derivative analysis. Interpretation results from both flow regimes show a very low kv/kh ratio in the segment around the well.All data tests were interpreted manually using practical equations after doing comprehensive literature studies. The data were also evaluated quantitatively using F.A.S.T WelltestTM – engineering software of pressure transient analysis from Fekete reservoir engineering software and services. Reservoir properties obtained from pressure transient analysis have similar results with the original data on the reservoir model. To simplify the study, production rate which was used in build-up and interference tests are only from oil production basis. In addition, no injections in Norne field were included during the tests to have the same comparison in all analysis. As the future work, any other types of tests are strongly recommended, both in single-well and multiple-well testing, also in vertical and horizontal wells.

The topic of this report is "Mobility of Residual Gas in Ormen Lange" and it has been prepared as a part of the course TPG4915 Petroleum Engineering - Reservoir Engineering, Master Thesis at the Norwegian University of Science and Technology (NTNU). The work has been performed on Ormen Lange, a natural gas field on the Norwegian continental shelf, operated by A/S Norske Shell.Substantial volumes of residual gas are present in the Ormen Lange field as a result of the hydrodynamic aquifer flow9. Total residual gas volume in 2007 is 80±30 Bcm gas depending on the residual gas saturation, Sgr. Depending on scenario 15±6 Bcm of the residual gas is recovered in 2040, and the recovery factor of residual gas is 15±5%. In general, with increasing residual gas saturation, residual gas volume increases and the recovery factor of the residual gas zones decreases.The main challenge and purpose of this project has been to understand the physics of residual gas during depletion, and to assess the potential recovery from the residual gas in different parts of the reservoir. A literature study aiming to identify the main driving parameters with respect to residual gas mobility has been conducted and used as a basis for subsequent simulation work.The need to understand the charge history of the field became important in 2008 when an appraisal well in the northern part of the field encountered only residual gas saturations in the crest of the structure and in the middle of the Direct Hydrocarbon Indicator (DHI). Core analyses, well logs and geological interpretation obtained during drilling and gas production in Ormen Lange so far allows the assessment of residual gas, and gives indications of where it resides in the reservoir. Residual gas saturations (Sgr) in the range of 0.21 to 0.41 have been observed in water-flood core measurements. Recovery of residual gas depends on the final reservoir pressure. The recovery from the residual gas zone in the south, where the reservoir is well depleted, is good compared to the north where the pressure depletion is limited. Applying the base case residual gas saturation value of 0.3 and assuming no mobility threshold above residual gas saturation (critical gas saturation is equal to residual gas saturation), the total recovery in 2040 of residual gas is 19%, see Figure 1. Future development plans will increase total residual gas recovery, as the pressure will be further depleted.In the South where an acting aquifer is present, recovery from residual gas highly depends on the strength of the aquifer. Earlier breakthrough of water with a potential stronger aquifer results in earlier shut-in of the wells, hence higher abandonment pressure and lower recovery of residual gas in the south. The critical gas saturation is one of the parameters that has been extensively investigated in this project. The critical gas saturation is the saturation at which a continuous gas flow can be first observed, coinciding with a non-zero gas relative-permeability. Most literature indicates that residual gas requires approximately 5% increase of gas saturation units in order to reach critical gas saturation. The implementation of the latter mobility threshold for residual gas in Ormen Lange reduces the total residual gas recovery by 2%. The flow rate of the remobilized gas depends on how fast the gas relative permeability increases during secondary drainage. Hence changing the slope of the gas relative permeability curve, Ng, and the endpoint value, krg, also affects the ultimate recovery of residual gas.

En god reservoarmodell, som både representerer de statiske parameterne og strømningsegenskaper, er avgjørende for å optimalisere produksjonen fra hvilket som helst reservoar. Mye tid og krefter blir brukt til å beskrive reservoaret så godt som mulig og store økonomiske beslutninger hviler på prognosene fra denne modellen. Prognoser utført ved bruk av flere realisasjoner basert på samme modell blir stadig mer populære for å fange usikkerhet. Historietilpasningsmetoder som Ensemble Kalman Filter er godt egnet for dette.EnKF ble foreslått av Evensen i 1994 som en data-assimilasjon metode innen oceanografi, og har blitt utviklet og testet flere ganger innen petroleumsindustrien siden da. Filteret bruker et ensemble av vektorer for å beskrive reservoarparameterne og hver av disse vektorene beskriver en realisasjon av reservoaret. Kovariansen mellom disse vektorene brukes til å representere både spredning og reservoarets respons til parameterverdier.I denne oppgaven har EnKF blitt brukt til historietilpasning av PUNQ S3, en syntetisk reservoarmodell, for å se effekten av tilgjengelig informasjon. Dette ble gjort gjennom to ulike simulering, hvor den første ble gjennomført med grenseverdier for å begrense de statiske parameterne. I det andre tilfellet ble utviklingen av en historietilpasning presentert gjennom ulike tidsskritt. Modellene ble evaluert på bakgrunn av sin prognose for fremtidig produksjon, samt sine avvik i parameterverdi sammenliknet med de sanne parameterne. Selv om prognosene ble forbedret for samtlige modeller, ble det ikke observert noen forbedring i reservoarparameterne. En utvikling mot en falsk løsning ble observert. Denne løsningen hadde feil parameterverdier, men gav en prognose for fremtidig produksjon som var veldig lik sannheten. Den geologiske kunnskapen ble ikke anvendt i oppdateringen, noe som førte til at de oppdaterte modellene var lengre unna sannheten enn det opprinnelige utgangspunktet.

World proved oil reserve gradually decreases due to the increase production but decrease new field discovery. The focus on enhance oil recovery from the existing fields has become more interesting in the recent years. Since waterflooding has been used in practices in secondary recovery phase for long time ago, the low salinity waterflooding is possible to apply as tertiary recovery phase. Another effective enhance oil recovery method is chemical flooding especially, nowadays, when the price of chemical is not a big issue compared to oil price. Both low salinity and chemical flooding method have been trialed and success in laboratory studies and some field tests. Moreover the salinity sensitivity on chemical flooding has been studied and both positive and negative results were proposed. Because new technology has been developing day by day in order to get higher oil recovery, the new technology as the combination of low salinity waterflooding and chemical flooding has been studied in this report. In this thesis, the literature of low salinity water flooding, alkaline flooding, surfactant flooding, polymer flooding and alkaline-surfactant-polymer flooding (ASP) have been reviewed. The mechanisms of each method that affect to oil recovery and salinity sensitivity on each chemical flooding method have been summarized. All of those studies showed the benefit of chemical to the low salinity water flooding. the result of literature reviews has turned to the numerical simulation part.The simulation has been carried out on a 3 dimensional synthetic model by using Eclipse 100 as the simulator. The model is heterogeneous with patterns variation in permeability and porosity. The effect of low salinity in water flooding, alkaline flooding, surfactant flooding, polymer flooding and ASP flooding have been observed in many aspects.The main role of low salinity effect in water flooding is wettability changing from oil-wet to water-wet. The low salinity water in the first water flooding phase give the positive effect but not much different compared to overall recovery. The low salinity in chemical solution influences an additional oil recovery in all combinations. Mainly, low salinity increases polymer solution viscosity that can improve sweep efficiency of polymer flooding. In alkaline flooding and surfactant flooding, the salinity is need to be optimized to optimum salinity condition corresponding to optimum alkaline concentration and surfactant concentration, where creates the lowest IFT. The range of secondary flooding for alkaline and surfactant flooding is when they reach the optimum concentration. In case of polymer, the viscous polymer solution can impact longer as the polymer injection range. In term of low salinity in tertiary water flooding, it influences better oil recovery than high salinity water flooding. Therefore, it can be concluded that low salinity water flooding gives a positive effect to overall result when combined with chemical flooding. The recommendations are also available for further study.

Bean Bazar gas field was discovered by Pakistan Shell Oil Company (PSOC) in 1960 and initial production started since 1999. The field has two wells-BB1 and BB2 and two sand groups- Upper Gas sand (UGS) and Lower Gas Sand (LGS). This is one of the condensate rich fields in Bangladesh. The field is produced by water drive. A huge amount of water is produced from the two sands. The proven gas reserve of this field was estimated approximately 230.80 Bcf. The total gas produced till December, 2011 was 75.65 Bcf. That is one-third gas had already been produced. The remaining gas is required to recover from the wells by predicting the present well and reservoir performance for a certain time based on the current production data. That is why, this task was liked by me when the authority proposed me.In this thesis work, a simulation model was constructed based on the latest production data. Vertical Flow performance (VFP) for BB1 and BB2, Change of transmissibility, Change of angle of aquifer etc. improved the recovery. Most of the geological data was taken from the "Simulation Study of Beani Bazar Field" by RPS Energy, U.K.2009. The simulation model was then run to forecast the future field performance to find out an optimal development plan for the field and to determine the reserve estimation.Simulation results showed that the ultimate recovery is very high in drilling wells but it involves a lot of cost. But there is no way out. The water must be controlled. The final recommendation for future work on Beani Bazar simulation model is that the water rise should be controlled by drilling a new well in the present reservoir a few km away from the existing wells. The quick gas production can bring huge water which should be handled by re-installing the plant infra-structure.

A great percentage of oil is observed to be left in the reservoir after the traditional primary and secondary recovery methods. This oil is described as immobile oil. Alkaline-Surfactants are chemicals used to reduce the interfacial tension between the involved fluids, while polymer is used in making the immobile oil mobile.Norne C-segment is in the decline stage and is facing considerable challenges regardingvolume of oil bye-passed due to water flooding. There is need for developing cost efficient enhanced oil recovery (EOR) methods that would be suitable for Norne fluid and rock properties and therefore improve sweep efficiency significantly. Based on literature and screening criteria, alkaline-surfactant-polymer can be used as an enhancing agent to produce extra oil and reduce water-cut significantly in the C-segment.The objective of this work is to evaluate the possibilities of using alkaline, surfactant and/or polymer to increase the oil recovery factor and prolong the production decline stage of Norne field. An initial study was conducted using heterogeneous synthetic models (with Norne Csegment fluids and rock properties) to assess the suitability of alkaline/surfactant/polymer (ASP) flooding. All the chemical cases simulated gave substantial incremental oil production and water-cut reduction. However, history matched Norne C-segment reservoir model was used to simulate alkalinesurfactant-polymer flooding using Eclipse 100. Appropriate chemical quantity for injection was ascertained by simulating several cases with different concentration, injection length and time of injection. Different sensitivity analyses were made and simulations revealed that the most effective method was not the most profitable. Having established most profitable method which was injecting ASP slug with a concentration of 7Kg/m3, 2Kg/m3 and 0.3Kg/m3 into C-3H (injector) for 4-years in a cyclic manner, an incremental recovery factor of 2.61% was recorded and Net Present Value (NPV) was calculated to be 1660 x103MNOK

SummaryThe displacement of oil from reservoir rock pore spaces is a function of many interacting variables, amongst which the reservoir wetting state has been shown to be one of the important affected by the rock lithology, oil chemistry and brine salinity. A finding from previous research says that the injection brine into oil saturated core plug increased oil recovery. Based on this the objective of this master thesis is to investigate the effect of brine concentration on flow properties in two types of carbonate rocks for enhanced oil recovery (EOR) through imbibition and water flooding processes.The methodology used to evaluate the effect of brine concentration (BC) and chemical composition (CC) for oil recovery consisted on two stages. The first stage covers the literature review regarding the effect of brine concentration and chemical composition, including carbonates (chalk and limestone) characteristics. The second stage is related to the laboratory experiment which was performed using n-Decane oil, six (6) brines with different concentrations and chemical composition and the six (6) core plugs where four (4) “chalks” from Ekofisk (Norway) and the other two (2) “limestones” from Iranian field. The experiment was carried out in the laboratory of Institute of Petroleum and Technology (IPT), the materials, chemicals products, apparatus and equipments, methodology and procedures were provided by the IPT laboratory.To carry out the laboratory experiments, initially the two cores from Iranian were cleaned before being used. Different properties of brines, cores and oil were measured using different methods and procedures; and results were computed. Next, each core was saturated with one type of brine and after that flooded by n-Decane oil for establishment of initial water saturation and determination of volume of oil produced by drainage process at room temperature conditions at one bar. After that, all cores were aging about 15 days at room temperature condition. Finally, each core was flooded using brine by imbibition process at room temperature conditions.Results achieved were computed and discussed based on the literature review and compared with “A salinity (AS) Ekofisk core reference case” and similar studies. From this study was observed that the matrix block has a high porosity. The average porosity was about 40.24% of the volumes of large pores. The average absolute permeability was about 3.73 mD which is low because the microporous dominate the pore network. The average brine density (ρ) was about1.026 g/cm3 and pH was about 7.25. The initial water saturation varies between 14.58 to 28.50% and residual oil saturation among 22.49 to 62%. The sleeve pressure in the cylinder was kept from 15 to 28 bar. During waterfloodig was observed that the breakthrough pressure drop and time to increases when the oil recovery increase.The highest original oil in place (OOIP) was achieved in the low salinity (LS) core which was about 68.46% and the lowest was recorded in the C salinity (CS) core which was around 26.71%. The reason of the high and the low recovery is related with the effect of brine concentration and chemical composition of Sodium, Calcium, Magnesium and Sulphate, added in the solution. The main driving mechanism for low salinity waterflooding is believed to be multi component ionic exchange made possible by the expansion of electrical double layer. The permeability and porosity of the cores can be pointed as other factor. In general, it was showen that there is an increase in oil recovery as the salinity decreases.