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An understanding of the mechanisms by which oil is displaced from porous media requires the knowledge of the role of wettability and capillary forces in the displacement process. The determination of representative capillary pressure ( ) data and wettability index of a reservoir rock is needed for the prediction of the fluids distribution in the reservoir: the initial water saturation and the volume of reserves. This study shows how wettability alteration of an initially water-wet reservoir rock to oil-wet affects the properties that govern multiphase flow in porous media, that is, capillary pressure, relative permeability, and irreducible saturation. Initial water-wet reservoir core samples with porosities ranging from 23 to 33%, absolute air permeability of 50 to 233 md, and initial brine saturation of 63 to 87% were first tested as water-wet samples under air-brine system. This yielded irreducible wetting phase saturation of 19 to 21%. The samples were later tested after modifying their wettability to oil-wet using a surfactant obtained from glycerophtalic paint; and the results yielded irreducible wetting phase saturation of 25 to 34%. From the results of these experiments, changing the wettability of the samples to oil-wet improved the recovery of the wetting phase.

Horizontal wells have become a popular alternative for the development of hydrocarbon fields around the world because of their high flow efficiency caused by a larger contact area made with the reservoir. Most of the analytical work done in the past on horizontal productivity either assumed that the well is infinitely conductive or the flow is uniform along the entire well length. The infinite conductive assumption is good only when the pressure drop in the wellbore is very small compared to the drawdown in the reservoir otherwise the pressure drop in the wellbore should be taken into account. In this paper, an improved predictive model that takes into account the effect of all possible wellbore pressure losses on productivity index of long horizontal well was developed. Results show that the discrepancies in the predictions of the previous models and experimental results were not only due to effect of friction pressure losses as opined by Cho and Shah but may also be due to all prominent pressure losses such as kinetic change and fluid accumulation experienced by the flowing fluid in a conduit. The effect is most pronounced at the early production time where initial transience at the onset of flow is experienced.

Proper slurry design is critical to the success of a cementing job. The best method to obtain a good slurry design with desired compressive strength is by laboratory experiments which involve experimenting different formulations and selecting the best composition for the specific cementing operation. This exercise is not only time consuming considering the amount of time required, but also expensive. Sixteen sets of experiments were conducted in the laboratory, and factorial design was used to design the experiments for the sensitivity analysis of four different factors impacting on the compressive strength of cement slurry. The responses from the 16 experimental runs were used to develop a model which can be used for optimization purposes. The model developed was simple, in agreement with the experimental data used and can be implemented using an ordinary simple calculator. Coefficients of main effects of X 1 , X 2 , X 3 , and

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Cuttings transport has a major impact on the economics of the drilling process. It is one of the major factors affecting cost, time and quality of drilling wells. In spite of the many technological advances that have attempted to prevent the cuttings transport along the fluid, one significant challenge remains predicting the effect of cutting transport on pressure drop. Many interdependent variables affect cuttings transport and the complexity of the phenomena present challenges to the production engineer whose tries to determine how the cuttings transport affect the pressure in vertical flow. Meanwhile, many correlations have been developed to determine the effect of cutting transport in vertical flow but there is little information related to effect of cuttings transport on pressure drop and cutting hold up along the vertical pipe. This paper presents comprehensive details of effect of cutting transport on pressure drop and the detrimental effect of drill cutting hold-up on fluid flow along the vertical pipe.

As the search for natural gas becomes increasingly high due to its high demand worldwide, the oil and gas industry is faced with the challenge of liquid loading in gas or condensate wells. It is imperative to properly design and predict the operational parameters necessary for handling flow assurance challenges due to simultaneous flow of gas with liquid. The model of Guo et al is the most recent systematic approach for predicting liquid loading in gas well. However, it did not account for the accumulation and kinetic terms in the momentum energy equation used to estimate bottom-hole pressure in a gas/oil/water/solid four phase flowing well. The two neglected terms in Guo et al formulation have significant effects on the gas well operational parameters such as the minimum gas flow rate for preventing liquid loading. This paper presents an improved model that describes a systematic approach for estimating liquid loading in a gas well without neglecting any term in the fundamental momentum equation. The results obtained showed that at the early production time where initial transience at the onset of flow is experienced, the critical gas flow rate obtained from the new model is lower than that predicted from Guo et al model due to inclusion of accumulation term while at the later production time, the critical gas flow rate obtained becomes higher than that predicted from Guo et al model and increases as the transient period elapses. Results further show that at some point during production, the minimum energy required to lift liquids out of the wellbore is more than that required at the earlier stage of production. The new model is reasonable, reliable and better when compare with Turner et al and Guo et al models. It is useful for operators to refine their procedures and better manage the risk of liquid loading during natural gas production.