Eldabbour, Mohamed (Abu Qir Petroleum) | Fadel, Ayman (Abu Qir Petroleum) | Soliman, Ali (Abu Qir Petroleum) | Safwat, Hatem (Abu Qir Petroleum) | Labib, Amr (Abu Qir Petroleum) | Belli, Andrea (Abu Qir Petroleum) | McLaughlin, Ryan (Corex U.K. Ltd) | Patey, Ian T.M. (Corex U.K. Ltd) | Munro, Murdo S. (Corex U.K. Ltd) | Jones, David (Corex U.K. Ltd)
Gravel pack completion operations are a sand production management technique that is considered successful if the well produces no sand and has minimal impact upon the potential productivity and hydrocarbon recovery. However, statistics show that many gravel packed wells suffer reduced productivity as a result of damaging mechanisms induced by gravel pack operations and completion fluids. This provides an opportunity for improved hydrocarbon recovery if the mechanisms are understood.
A study was conducted to simulate the alterations caused by the gravel pack operations including gravel carrier fluid, completion fluid and lost circulation material. Simulations using reservoir core samples were carried out at near-wellbore conditions, in order to examine operational fluid interactions with the reservoir and assess the impact of a stimulation fluid. Cores from a range of rock types were selected, and prepared to initial gas-leg saturation. An operational sequence consisting of completion fluid, gas production, stimulation fluid, completion fluid, and production of gas was carried out, with permeability measurements before and after the sequence.
In all core samples, the introduction of the completion fluid during gravel pack installation resulted in alterations of 30-60% reduction in core permeability. Geological interpretative analysis showed damage mechanisms including clay fines movement and pore blockage, dissolution of native cement, and retention of operational fluid in the pores. It was believed that retention of fluids was having the most significant impact upon permeability. Stimulations were carried out for all samples to quantify the effect of acid on removing the formation damage resulting from the gravel pack operations. The experiments showed 5-10% improvement on average except for one core sample, which showed 40% improvement.
Based upon the previous results, a modified sequence was examined, utilizing an alternative stimulation fluid/acid sequence and adding an extra operational stage. The experiments showed that after treatment an improvement of around 10% was noted, and after an additional stage, a further 8% improvement was seen. The final permeability was over 80-90% of the initial permeability, indicating that there was the potential for good productivity and recovery of hydrocarbons.
The results of the study were applied to seven gravel pack jobs in three wells and the field results showed the reduction in productivity after gravel pack installation was around only 10%, compared to previous wells which showed more than 50% reduction in productivity.
The well will immediately be brought on production and is expected to flow at more than 100 MMscf/D of gas and 3,000 B/D of associated condensate, the company said. The French major is racking up barrels of deepwater production as part of its large-scale West African push. Since 2007, an operator in Nigeria has registered a significant increase of oil-spill events caused by sabotage and oil-theft activities. The technology presented here allows detecting and locating leaks taking place at a distance from the sensor of up to 35 km.
By racking up exploration agreements in the United Arab Emirates, Oman, and Bahrain, Eni took a big step forward in its pledge to tap into the Middle East’s vast swaths of highly prospective oil and gas acreage. Three onshore fields in the Emirate of Sharjah, United Arab Emirates, have more than 30 years of production history from more than 50 gas-condensate wells. For the next several years, supplies of crude will depend on several macro factors. Some are easier to forecast than others. The French major will become operator of the Ruwais Diyab concession, and ADNOC says additional companies are lining up to partner on the emirate’s other unconventional areas.
The Caribbean nation hopes the auction will lead to at least two exploration projects in a region that has become increasingly attractive thanks to new discoveries and investments made in neighboring countries. This new development is the first to recover commercial quantities of oil in the UK from reservoirs that are generally considered non-productive. The explorer has so far encountered 400 ft of reservoir pay zone in an area where it has three other producing fields. The state-run offshore company has found a gas and condensate field that holds an estimated 250 million BOE. DEA Deutsche Erdoel is buying Sierra Oil & Gas, giving the German operator stakes in six new blocks off Mexico—including the Zama discovery, where appraisal drilling is now under way.
Africa (Sub-Sahara) Eni started production from the West Hub development project's Mpungi field in Block 15/06 offshore Angola. The startup follows the project's first oil from the Sangos field in November 2014 and the Cinguvu field last April. Mpungi will ramp up West Hub oil production to 100,000 B/D in the first quarter from a previous level of 60,000 B/D. The project also includes the future development of the Mpungi North, Ochigufu, and Vandumbu fields. Eni is the block operator with a 36.84% stake. Sonangol (36.84%) and SSI Fifteen (26.32%) hold the other stakes.
Formation damage in gas/condensate reservoirs can be caused by a buildup of fluids (condensate) around the wellbore. This reduces the relative permeability and therefore gas production. This page discusses condensate banking and how to overcome its effects. As shown in Figure 1, gas/condensate reservoirs are defined as reservoirs that contain hydrocarbon mixtures that on pressure depletion cross the dewpoint line. In such instances as when the bottomhole pressure is reduced during production, the dewpoint pressure of the gas is reached in the near-wellbore region.
Ganjdanesh, Reza (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin) | Fiallos, Mauricio Xavier (The University of Texas at Austin) | Kerr, Erich (EP Energy) | Sepehrnoori, Kamy (The University of Texas at Austin) | Ambrose, Raymond (EP Energy)
As the pressure drops below dew point in an unconventional gas-condensate reservoir, the liquid drops out of gas phase and forms an oil phase in matrix and fracture. The volume of oil phase formed in the matrix mostly stays below the residual oil saturation, i.e., the oil will be trapped in matrix permanently if enhanced oil recovery techniques are not applied. The gas huff-n-puff process has been performed and shown the potential of improving the recovery from tight oil reservoirs. The objective of the study was to investigate the feasibility of huff-n-puff EOR in a gas condensate reservoir. The studied section of the field contains 13 horizontal producers. The wells have been producing for 4 to 8 years and the oil production rate of each well declined below 10 barrels per day.
Compositional reservoir simulation was used to predict the performance of enhanced oil recovery. A sector model was built for the area selected as the prospective candidate for gas injection. The embedded discrete fracture model (EDFM) was used for modeling the fractures, improving the CPU time by an order of magnitude compared to the local grid refinement method. A Peng-Robinson equation-of-state model was prepared based on the early produced samples from the wells. The only available gas for injection was the produced gas from the surrounding producers. A thorough phase behavior analysis was conducted to understand the miscibility of the injected gas and the in-situ fluid.
The well interference through fracture hits plays an important role in the studied reservoir. The image logs from the surrounding wells show the abundance and extent of the long fractures connecting multiple producers. The long fractures can impede the pressure buildup during gas injection and hamper the gas huff-n-puff performance. Several long fractures were added to the reservoir model to capture the characteristics of well interference.
Gas condensates are liquids, generally straight chain alkanes in the C2 to C6 range, that can condense from gas when the temperature and pressure drop sufficiently low. The terms "condensate" and "distillate" are used interchangeably to describe the liquid produced in tanks, but each term stands for a different material. The liquid has been called "distillate" because it looks like products obtained in refineries by distilling the volatile components from crude oil. But it has also been called "condensate" because it is condensed out of the gas produced by the well. Lease condensate, called so because it is produced at the leas level from oil or gas wells, is the most commonly discussed type of gas condensate.