CO2 injection is considered as one of the successful methods used for enhanced oil recovery (EOR) in oil fields to recover residual oil. It increases mobility and reduces viscosity and interfacial tension. Asphaltene precipitation and deposition phenomena appear in petroleum reservoirs due to change in temperature, pressure, and liquid phase compositions; either during the primary production or enhanced oil recovery processes. Asphaltene precipitation might occur due to CO2 injection in light oil (>30° API) reservoirs which may cause blockage of production system, decrease in permeability, wellbore plugging and change in porosity. Experimental data concludes high asphaltenes precipitation and lower asphaltene solubility in light oils. Hence severe damage to formation can happed sue to asphaltene precipitation, in some cases the loss might be irreversible. This paper furnishes the investigation of asphaltene precipitation caused by CO2 injection. In this regards interaction between asphaltene and formation, precipitation quantity under different injection flow rates of CO2 at the constant injection pressure have been investigated. Results conclude that there is direct proportionality between asphaltene precipitation and amount of injected gas in the core sample, whereas inverse proportionality between asphaltene precipitation and increased injection flow rate of the gas at constant injection pressure.

It has long been proved experimentally that the tight gas sands are more pronounced to stress changes as compared to moderate and high permeability reservoirs because of the narrow flow channels of the formation [1]. The consideration of the effect of stress in the evaluation and production performance of tight gas reservoirs is very important in order to make right decisions regarding their development. Due to hydrocarbon production, the effective stress increases causing a reduction in permeability and porosity of the porous medium.The conventional pressure transient analysis techniques in gas wells based on constant permeability would become unreliable [2]. Consequently, the incorrect evaluation of permeability leads towards wrong decision regarding well stimulation. Also the inflow performance modeling of tight gas reservoirs based on constant permeability will not be corrected as far as evaluation of well's production potential is concerned.Few studies on tight gas reservoirs considering the effect of stress sensitive permeability used the Raghavan's stress dependent pseudo-pressure approach [3] for which pressure vs. permeability data was determined experimentally. But, if laboratory data is not available then there is need to develop an analytical approach to generate the pressure vs. permeability data required for the use of stress dependent pseudo-pressure in reservoir evaluation and production performance studies in tight gas reservoirs.The objective of this paper is to develop an analytical approach, in the absence of lab data, to generate pressure vs. permeability data for the determination of stress dependent pseudo-pressure. This stress dependent pseudo-pressure is used for well test analysis to determine the stress sensitive formation permeability and also to generate production performance in tight gas reservoirs. The developed technique has also been implemented on the field data of a tight gas reservoir tovalidate the results by using actual well's production history.

Dealing with mature fields in a period of low oil price, companies have focused their activity on intensive rig-less campaigns aimed at increasing fields’ recovery factors and production. Aging of the fields together with pressure decline and onset of water production has added the complexity of scale deposition in numerous wells. Scale can deposit at any location that is in contact with water, such as in the reservoir, well bore, tubing, top side and processing facilities and cause production decline and flow restriction if not properly controlled. This paper will be dedicated to show the selection of the right subsurface intervention technique and the prevention of scales re-occurrence has been wisely decided based on scale management approach which covers scale prediction and prevention techniques. Conventionally, scale is controlled by the use of chemical inhibitors either by squeeze treatment into the reservoir or continuous / batch injection into the well. ‘’Prevention is better than cure’’ is the right motto for preventing re-occurrence of scale. Successful experience gained through the application of some new scales inhibition techniques was the key to implementing these preventive methods on different wells in operated and non-operated fields.

Hydraulic fracturing is the technique which is key to success in developing Shale/ Tight Reservoirs. Hydraulic frac job cost is a challenge which sometime is more than the actual drilling cost while 70% of that pertains to the products (i.e. Fluid, proppant etc). Major components of frac fluid consist of Guar while proppant consist of sand/ synthetic sand. Pakistan is one of the guar gum producer country in the world along with long coastal area with abundant sands, covering the wide range of stresses. So far, no research has been undertaken to make this technique economical therefore, utility of indigenous resources needs to be explored. Cost optimization of this technique using indigenous resources will help in untapping these resources at booming economy, helping in saving petrodollars and in the meantime generating a huge volume of economic activity in the country. This paper describes the need for researching on indigenously developed frac fluid and sand used as proppant to improve well productivity.

Gas compression has been widely adopted by the petroleum industry and is validated as a reliable method for improving reserves base. As depletion drive gas fields mature, their reservoir pressure declines with an associated reduction in gas production rates. This phenomenon is even more pronounced in fields where aquifer water breaks through and results in rapidly falling well head pressures which naturally result in reduced reserves recovery over the producing life of the field. Compression at wellhead or at the facility elongates well and field life resulting in tapping additional reserves, which may be left behind in case surface compression facilities are not put in place in a timely and phased manner. Compression was initiated at Bhit Gas Field from 2009 and implemented in a phased manner over several years. In first phase, well head compression was deployed to ensure a continuous plateau rate and provide additional gas recovery at 100 psig suction pressure which was selected through matching compressor curves against well deliverability. In second phase, booster compressors at selected wellheads were installed to further drop pressures d upto 50 psig. This was followed by optimization where existing compressors were not only swapped, relocated and reconfigured but also spare compression capacity was utilized by merging wellhead to nodal compression to further drop pressures upto 20 psig leading to increased recovery. Surface optimization actions were justified by set of forecasted results from simulation model utilizing compressor curves. This paper will demonstrate the continuous surface optimization performed as a function of reservoir and well response with the ultimate aim of enhancing reserves recovery by comparing actual field performance with Forecasts from a numerical simulation model. Highlights on the benefits of timely identification and implementation of compression needs achieved through significant cost savings and reduced project time to market will also be presented