Horizontal wells are drilled to achieve improved reservoir coverage, high production rates, and to overcome water coning problems, etc. Many of these wells often produce at rates much below the expected production rates. Low productivity of horizontal wells is attributed to various factors such as drilling induced formation damage, high completion skins, and variable formation properties along the length of the wellbore as in the case of heterogeneous carbonate reservoirs. Matrix acidizing is used to overcome the formation damage by injecting the acid into the carbonate rock to improve well performance. Designing the matrix acidizing treatments for horizontal wells is a challenging task because of the complex process. The estimation of acid distribution along wellbore is required to analyze that the zones needing stimulation are receiving enough acid. It is even more important in cases where the reservoir properties are varying along the length of the wellbore. A model is developed in this study to simulate the placement of injected acid in a long horizontal well and to predict the subsequent effect of the acid in creating wormholes, overcoming damage effects, and stimulating productivity. The model tracks the interface between the acid and the completion fluid in the wellbore, models transient flow in the reservoir during acid injection, considers frictional effects in the tubulars, and predicts the depth of penetration of acid as a function of the acid volume and injection rate at all locations along the completion. A computer program is developed implementing the developed model. The program is used to simulate hypothetical examples of acid placement in a long horizontal section. A real field example of using the model to history match actual treatment data from a North Sea chalk well is demonstrated. The model will help to optimize acid stimulation in horizontal wells.

Pore pressure exists ubiquitously in the Earth’s subsurface and very often exhibits a cyclic loading on pre-existing faults due to seasonal and tidal changes, as well as the impoundment and discharge of surface reservoirs. The effect of oscillating pore pressure on induced seismicity is not fully understood. This effect exhibits a dynamic variation in effective stresses in space and time. The redistribution of pore pressure as a result of fluid flow and pressure oscillations can cause spatial and temporal changes in the shear strength of fault zones, which may result in delayed and protracted slips on pre-existing fractures. This research uses an experimental approach to investigate the effects of oscillating pore pressure on induced seismicity. With the aid of geophysical techniques, the spatial and temporal distribution of seismic events was reconstructed and analysed. Triaxial experiments were conducted on two types of sandstone, one with low permeability (Fontainebleau sandstone) and the other with high permeability (Darley Dale sandstone). Cyclic pore pressures were applied to the naturally-fractured samples to activate and reactivate the existing faults. The results indicate that the mechanical properties of the sample and the heterogeneity of the fault zone can influence the seismic response. Initial seismicity was induced by applying pore pressures that exceeded the previous maximum attained during the experiment. The reactivation of faults and foreshock sequences was found in the Fontainebleau sandstone experiment, a finding which indicates that oscillating pore pressure can induce seismicity for a longer period of time than a single-step increase in pore pressure. The corresponding strain change due to cyclic pore pressure changes suggests that progressive shearing occurred during the pore pressure cycles. This shearing progressively damaged the existing fault through the wearing of asperities, which in turn reduced the friction coefficient and, hence, reduced the shear strength of the fault. This ‘slow’ seismic mechanism contributed to the prolonged period of seismicity. This study also applied a material forecast model for the estimation of time-to-failure or peak seismicity in reservoir-induced seismicity, which may provide some general guidelines for short-term field case estimations.

Pore pressure exists ubiquitously in the Earth’s subsurface and very often exhibits a cyclic loading on pre-existing faults due to seasonal and tidal changes, as well as the impoundment and discharge of surface reservoirs. The effect of oscillating pore pressure on induced seismicity is not fully understood. This effect exhibits a dynamic variation in effective stresses in space and time. The redistribution of pore pressure as a result of fluid flow and pressure oscillations can cause spatial and temporal changes in the shear strength of fault zones, which may result in delayed and protracted slips on pre-existing fractures. This research uses an experimental approach to investigate the effects of oscillating pore pressure on induced seismicity. With the aid of geophysical techniques, the spatial and temporal distribution of seismic events was reconstructed and analysed. Triaxial experiments were conducted on two types of sandstone, one with low permeability (Fontainebleau sandstone) and the other with high permeability (Darley Dale sandstone). Cyclic pore pressures were applied to the naturally-fractured samples to activate and reactivate the existing faults. The results indicate that the mechanical properties of the sample and the heterogeneity of the fault zone can influence the seismic response. Initial seismicity was induced by applying pore pressures that exceeded the previous maximum attained during the experiment. The reactivation of faults and foreshock sequences was found in the Fontainebleau sandstone experiment, a finding which indicates that oscillating pore pressure can induce seismicity for a longer period of time than a single-step increase in pore pressure. The corresponding strain change due to cyclic pore pressure changes suggests that progressive shearing occurred during the pore pressure cycles. This shearing progressively damaged the existing fault through the wearing of asperities, which in turn reduced the friction coefficient and, hence, reduced the shear strength of the fault. This ‘slow’ seismic mechanism contributed to the prolonged period of seismicity. This study also applied a material forecast model for the estimation of time-to-failure or peak seismicity in reservoir-induced seismicity, which may provide some general guidelines for short-term field case estimations.

It is widely understood that injection and production activities can induce additional stress fields that will couple with the in situ stress field. An increased shear stress may cause serious casing stability issue, and casing integrity is one of the major issues in the development of an oilfield. In this thesis, I will present a methodology for semi-quantitatively addressing the physical processes, the occurrence, and the key influential factors associated with large-area casing shear issues in Daqing Oilfield. In the research, I will investigate reservoir heterogeneity and the far-field stress field in the Daqing Oilfield, China; I will review fundamental theories of rock strength, rock failure, casing shear, and techniques for coupling fluid flow and mechanical response of the reservoirs; and I will present mathematical simulations of large-area casing shear in one typical area (X1-3B) in Daqing Oilfield, under different regimes of water-affected shale area ratio and block pressure difference. Heterogeneity in Daqing Oilfield varies according to the scale. Mega-heterogeneity is not too serious: the geometry of the oilfield is simple, the structure is flat, and faults are numerous and complex, but distributed evenly. Macro-heterogeneity is, however, intense. Horizontal macro-heterogeneity is associated with lateral variations because of different depositional facies. Vertical macro-heterogeneity of Daqing Oilfield because of layering is typified by up to 100 individual sand layers with thickness ranging from 0.2 to 20 m and permeability ranging from 20 to 1600 mD (average 230 mD). Furthermore, there are a number of stacked sand-silt-shale (clastic lithofacies) sequences. Mercury porosimetry and photo-micro-graphic analyses were used to investigate the micro-heterogeneity of Daqing Oilfield. This method yields a complete pore size distribution, from several nanometers to several thousands of micro-meters as well as cumulative pore volume distributions, pore-throat aspect ratios, and fractal dimensions. The fractal dimension can be used to describe the heterogeneity at the pore scale; for sandstones, the larger the fractal dimension of a specific pore structure, the more heterogeneous it is. Reservoir sandstones of Daqing Oilfield have similar porosity and mineralogy, so their micro-heterogeneity lies in a micro-structure of considerable variability. Differences in micro-structure affect permeability, which also varies considerably and evidences a considerable amount of micro-scale anisotropy. Finally, the number and nature of faults in the oilfield make the macro-scale heterogeneity more complex. Rock strength is affected by both intrinsic factors and external factors. Increased water saturation affects rock strength by decreasing both rock cohesion and rock friction angle. In Daqing Oilfield, is seems that a 5% increase of water content in shale can decrease the maximum shearing resistance of shale by approximately 40%. Hysteretic behavior leads to porosity and permeability decreases during the compaction stage of oilfield development (increasing σ'). Also, injection pressures are inevitably kept as high as possible in the pursuit of greater production rates. These lead to non-homogeneous distributions of pressures as well as in changes of material behavior over time. Loss of shear strength with water content increase, inherent reservoir heterogeneity, and long periods of high-pressure water injection from a number of wells are three key factors leading to casing shear occurring over large areas in Daqing Oilfield. Reservoir heterogeneity and structural complexity foster uneven formation pressure distribution, leading to inter-block pressure differences. Sustained long-term elevated pressures affect overburden shale mechanical strength as well as reducing normal stresses, and the affected area increases with time under high-pressure injection so that the affected areas overlap at the field scale and alter the in situ stress field. Once the maximum compressive stress parallels or nearly parallels the differential pressure, and the water-affected shale area is big enough, the shear stability of the interface between the shale and the sandstone is severely compromised, and when the thrust stress imposed exceeds the shearing resistance, the strata will slip in a direction corresponding to the vector from high-pressure to low-pressure areas. The change in this slip and creep displacement field is the major reason for the serious casing deformation damage in Daqing Oilfield. To quantify the scale effect of the water-affected shale area on casing stability, coupled non-linear poroelastic fluid flow was simulated for a typical area. The Daqing Oilfield simulation result is in coincidence with the in situ observation of disturbed stress fields and casing displacement. The water-affected area has a scale effect on the casing stability. The ratio of the water-affected shale formation area to the total area influences the stability coefficient much more than the block pressure difference. In the studied area, under conditions of injection pressure of 12.7 MPa and no more than 2.5 MPa block pressure difference, the water-affected ratio should be smaller than 0.50 or so in order to maintain areal casing stability. By history matching, in the studied area under current development condition and considering the water-affected ratio, so long as the injection pressure and pressure differential between blocks are controlled to be less than 12.7 MPa and 0.86 MPa respectively, formation shear slip along a horizontal surface will no longer occur.

The Ebola viruses cause sporadic outbreaks of Ebola hemorrhagic fever (EHF) where origins have been traced to the continent of Africa and the Philippines. Since the initial discovery of Zaire and Sudan ebolavirus in 1976, the Ebola viruses have been responsible for severe hemorrhagic fever outbreaks in Africa with case fatality rates between 40-90%. The natural reservoir(s) of the Ebola viruses is currently unknown, but there is mounting evidence that fruit bats may play a key role. The goal of the current study is to screen a large variety of bat species from Africa and Asia where Ebola is known to be endemic for the presence of IgG specific antibody to Ebola virus in order to see which bat species may show evidence of past Ebola virus infection. Ebola virus would not be expected to cause lethal disease in its natural reservoir; therefore the presence of IgG antibody would be present. Identifying the species of bats that have been infected will allow researchers to hopefully isolate Ebola virus from bats adding to the evidence that bats are a reservoir species. The knowledge gained may also provide clues to new species of bats yet to be identified as possible natural reservoir(s) as well as expand the known geographical range of known Ebola virus outbreaks. Knowing which species of bats as well as their geographic range may help prevent future Ebola outbreaks by minimizing human-reservoir contact.

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.