Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Unavailability of gas transmission network near a hydrocarbon discovery leading to high pipeline infrastructure development cost and can cause delays in production or remain stranded, for several small gas reservoirs. This study explores the avenues of exploiting small and stranded gas reservoirs, through virtual gas pipeline by compressing the gas and transporting it through bulk transportation modules, primarily for use at Captive Power Plants, Processing Industries and CNG Stations. Virtual Pipeline (VP) system is being effectively used in many parts of the world for production from low volume stranded gas reservoirs. In Pakistan, presently, three stranded gas reservoirs are producing about 4 MMscfd gas through VP system in the Northern region of the country with the first such system being operative since 2010. Whereas, several opportunities exist in the Southern region of the country, as well, to add production from stranded gas reservoirs to national energy network through VP system. An economic model has been developed for the operators to assess the viability of VP vis a vis gas transmission pipeline and bring low volume stranded gas into the system. Results of economic model indicate that for small stranded discoveries with uncertainties in connected hydrocarbon volumes, production through VP offers better NPV than the conventional pipelines. Based on economic model, the concept of VP was implemented at one of PPL’s well, which commenced production on 27 October 2017, and currently producing 1.4 MMscfd gas and 110 bbl/d of condensate. Based on the collected data, if higher hydrocarbon volumes in place are estimated, the feasibility of laying feeder line to a nearest processing facility may be re-evaluated to compare with the currently utilized VP system.
The transportation of natural gas from hydrocarbon producing fields to consumption areas require a dedicated gas transmission pipeline network. With the advent of industrialization and urbanization, increase in gas prices has made it economically feasible to bring several smaller and remote gas well into production by connecting to the gas transmission network in the vicinity. Unavailability of gas transmission network in the vicinity of a hydrocarbon discovery leading to high pipeline infrastructure development cost and can cause delays in production from several stranded small gas reservoirs.
Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.
Sand production has always been a challenge for oil operators worldwide. Several parameters can lead to sand production, including poor cementing material in the reservoir, high production rates, and high drawdown applied to an unstable zone. The subject field consists of 105 wells; 90 of these wells are oil producing wells, 11 are water injection wells, two are dump flood wells, and two are water source wells. The primary challenge was to perform a gravel pack job on a high permeability water source well to deliver a planned rate of 25,000 bwpd.
A study for the formation, the area, and the history of gravel packing in the operator fields was made to provide the optimum solution for the target well. The well was categorized as a critical well because of the various challenges and because of its importance to the operator in supplying the field with the injection water, which was down for months. The completion specifications, sizes, and the pumping techniques were agreed upon with the operator and the critical well review team. The well suffered from high losses resulting from the high permeability and long interval. The fluid losses had to be controlled before running in with the completion equipment and pumping the gravel pack treatment to avoid premature screenout.
After perforating the pay zone, the well, as expected, suffered from high losses. These losses were controlled by pumping several non-damaging fluid loss pills until the losses were suitable for running the gravel pack assembly in the hole. The treatment was pumped in alternating stages of clean fluid and slurry fluid to aid in the displacement of the proppant in the annular space and to minimize the risk of bridging.
Premium screens (6-5/8 in. with 175 micron filter) were used along with a 40/60 proppant. A 5-in. wash pipe was used to force the majority of the fluid in the slurry to remain in the casing/screen annulus to maximize sand transport, rather than leaking off through the screen and into the screen base pipe/wash pipe annulus.
The treatment was successfully pumped, covering the 500 ft of screens and leaving excess volume of sand covering the blanks. The well was completed with an electrical submersible pump (ESP) and is producing 11,500 bwpd with no reported issues.
The injection in the field is now online after being down for five months as a result of shutting down the well.
For the heavy oil fields of the Orinoco oil belt in Venezuela, a new cementing concept was successfully applied to maintain zonal isolation during long term exposure to temperatures up to 1,202°F (650 °C) in a process called in-situ combustion. These unconventional wells are often associated with weak and unconsolidated formations complicating proper cement placement and the resulting cement sheath must withstand extreme stresses due to the temperature and pressure cycles during the in-situ combustion process.
During a comprehensive lab study API cement based slurries were engineered with high temperature stable aluminosilicate fibers. The corresponding cement specimens were cured and then exposed in a furnace with temperature cycles up to 1,202°F (650 °C) simulating the anticipated wellbore changes. Mechanical properties and permeabilities of these cementing systems were used in a computerized cement-sheath model to evaluate potential failures from stresses during the in-situ combustion process.
The cementing systems containing 50% of the aluminosilicate fiber were suitable to withstand thermal degradation without any visual cracks. The computerized cement-sheath simulations indicated that stresses induced by prompt pressure and temperature changes during the heat cycles are not causing failures for the lead cement sheath which was critical to provide zonal isolation above the combustion zone. The biggest improvement of this thermal shock resistant cementing system towards the corresponding cementing systems not containing the aluminosilicate fibers was the significantly reduced Young's modulus by around -20%, while the tensile strength increased by at least +60% resulting in a desired resilient cement sheath. The actual cement jobs in the field were successfully executed as planned without any losses or incidents. So far, no well integrity issues have been observed since the well was cemented in March 2012 with the following combustion process.
The thermal shock resistant cementing system, based on API cement, has advantageous towards refractory cements (such as high alumina cements) due to economics, ready availability, but in particular because it performs reliably by adjusting the slurry performance with common chemical admixtures and being flexible in design simplifying operations while contributing to a high-quality job.
GUPCO is one of the largest E&P Companies in Egypt and Middle East. It has a vast infrastructure with a large number of wells, platforms, pipelines and offshore facilities. GUPCO's peak production exceeded 600,000 BOPD in 1983 while it produces around 100,000 BOEPD today from more than ten geological formations in Gulf of Suez (GoS). GUPCO produced more than 4.6 billion STBO which represent more than 43% of Egypt's total cumulative oil to date. And in spite of that, we still have many opportunities and success yet to achieve.
As one of the petroleum industry leaders, GUPCO was and will always seek success and excellence in managing its assets. For more than fifty years, GUPCO used to follow the highest standards available in petroleum industry, and applied them in all areas to achieve that outstanding excellence. From day one, GUPCO realized that understanding subsurface features and optimizing recovery from different fields are the key areas among all. As a result, GUPCO had made concerted efforts in those areas in specific.
Managing giant fields is not an easy task; it requires special knowledge and experience to manage such critical asset since each 1% increment of oil recovery means tens of millions of oil barrels. And because GUPCO has four giant fields, it was serious for us to do our best to maximize their value. GUPCO started that early whilst exploration phase, appraisal, development and currently in maturity phase. Along these different phases, we utilized wide spectrum of tools starting from basic technical elements (e.g. flow equations, DCA, MBE, PTA… etc.) reaching to state-of-the-art techniques and technology available (e.g. Numerical Modeling, Artificial Intelligence and EOR) at which GUPCO uses numerical reservoir simulation extensively, utilizes neural network in different applications, and already applied TAP (Thermally-Activated Particles) technique which is called commercially BrightWater® to improve sweeping efficiency, and also studied feasibility of Low Salinity Waterflooding (LoSalTM) which is planned to be implemented in near future after upgrading water injection facilities.
In this paper, we are going to present various case studies with detailed elements GUPCO followed to accomplish that success in managing giant fields, and how such powerful techniques contributed in maximizing our asset value. We'll explain also what we did from day one highlighting different challenges we faced and how we managed to solve them, and more importantly, we'll elaborate our experience in dealing with giant fields under all levels of field's maturity, highlighting the importance of many tools we've utilized. And ultimately, proposing guidelines to be followed whilst applying Waterflooding for utmost benefit.
Colombia is 28th economy in the word, with important resources: 21th crude oil producer in the world with 1004,000 barrels per day, 40th of refined petroleum products: 316,500 million tons, 41th of natural gas: 11,260,000,000 cubic meters, 10th of coal: 85.8 million tons per year. Colombia expects 10 billion dollars in international investment in mining-energy sector in 2013. Colombia nearly doubled crude production during previous seven years. Rising exploration indicators: 131 exploratory wells were drilled in 2012.
The goal is increasing reserves/production ratio, today is 7 years, and consequently first challenge is increasing of reoccurring factor. Currently it is about 18-19 percent, so goal is to rise by 10 percent during next 20 years adding more 3 billion barrels of oil reserves by implementation of new technologies such as improved & enhanced oil recovery, which can also be used on recent producing fields, as well as new ways available to redevelop mature fields: new reservoir models, new drilling technologies and surface facilities with investments in old fields, to provide new production and cash flow. To increase transportation capacity will be invest about 5 billion dollars during next years. The bicentenario pipeline will add up 120,000 barrels per day. Currently transportation goes to the Caribbean (Atlantic), project in preliminary stages is a pipeline to the Pacific with 250,000 barrels per day.
The second challenge is unconventional oil and gas (shale gas & liquids, tight gas & oil, heavy oil & bitumen, coal bed methane & gas hydrates) exploration and production. Colombia has seven basins of those recourses, the third country after Argentina and Brazil in South America with the highest potential for unconventional reservoirs, presuming the positive investment climate.
An analysis of unconventional oil and gas modern trends and future needs in Colombia with projection to 2030was made in this work.
Bounded thin oil reservoir, which is characterized by less reserves, thin thickness, and weak energy of edge or bottom water, could hardly be developed with high cost, low recovery and high risk. Bajiaoting oil field, which is located in East China Offshore, has all the characteristics of bounded thin oil reservoir, what’s more, it has low permeability, less than 10mD. As a result, it could not be developed without water injection wells, but water injection cases could not be taken in East China Offshore due to the restrictions of the producing platform. Face all the difficulties, Water Dumping, which could maintain pressure and improve recovery with low cost, was applied in Bajiaoting oil field, and it is the first time that this technology applied in China offshore. Traditionally, water injection wells are located in the edge of the reservoirs and oil wells are located in the middle area. By contrary, new case was put forward: transforme the oil well which located in the center into water dumping well in the appropriate time. Therefore, dumping water could spread from edge to the center, and then, to the other edge. In this study, related calculation methods for preesure and injection rate are applied, and the effects and simulation results of some adjustment cases are discussed.
Seismic imaging in the Gulf of Suez is severely affected by salt plays, strong multiple contamination and raypath distortion etc. Consequently, geophysicists face challenges while interpreting the existing surface seismic and planning new wells, both in time as well as depth domain, and encounter surpirses while drilling. Borehole seismic is commonly used to address some of the seismic issues, which could also result in big uncertainties if not planned properly in challenging environment.
In this paper, we present case studies from two areas in the Gulf of Suez where borehole seismic surveys were conducted in different configurations in wellbores with different geometries. Logging programs were defined after pre-survey ray trace modeling simulating different scenarios and careful planning considering the operational and geological challenges and logistics. Full waveform processing of well data resulted in much higher resolution 1D to 2D images in time and depth. Borehole seismic images were integrated with the existing surface seismic. In the first area, integrated analysis helped in horizon and structural interpretation revealing features not seen on low resolution surface seismic time and depth cubes. Seismic uncertainties for shallow as well as deep targets were resolved and fault interpretation was refined. Additionally, integrated analysis helped to detect new faults successfully, indicating new promising area for future development drilling. In the second area, integrated analysis confirmed presence of multiples in the surface seismic resulting in the target horizon deeper than expected, which was interpreted shallower all over the area. Analysis also confirmed change in the depositional environment in the area indicating a new block to be studied and estimated.
In this paper, we present case studies from Ras Fanar (Gulf of Suez West Concession) and Ras Budran (Gulf of Suez East Concessions) fields in the Gulf of Suez Offshore, Figure 1. Both oilfields were discovered in 1978 and are operated by Suez Oil Company, joint venture of RWE Dea and Egypt General Petroleum Corporation (EGPC). Surface seismic data in the Gulf of Suez is affected by strong contamination by multiples, weak subsalt reflection strength, and strong raypath distortion (Domenico, 1977 and Lewis et al, 1995), and is of low resolution typically. Therefore, existing conventional surface seismic in these fields is no exception making the interpreter's job difficult. Both explorationists and reservoir characterization specialists have identified the importance of borehole seismic or commonly known as Vertical Seismic Profiling or VSP (Hardage, 1985) over the years as aid to the above. Suez Oil Company also conducted standard zero offset (source position at some distance from the well) Checkshots or VSPs to address a few of these challenges in the area, but the problem remained unsolved since most of the wells drilled are deviated from a single platform. Even the time-depth relationship could be inaccurate in such complex subsurface environment. The problem is more serious due to severe ray paths bending and oblique incident angles when the well deviation increases, which is very common in the current drilling campaign. It can be addressed by acquiring data in appropriate survey configuration in different well geometries after pre-survey modeling and proper planning. Integrated approach can further help in data interpretation and resolve seismic uncertainties.