|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Africa (Sub-Sahara) Anglo African Oil & Gas encountered oil at the TLP-103C well at its Tilapia license offshore the Republic of Congo. The well intersected the targeted Djeno horizon, and wireline logging confirmed the presence of a 12-m oil column in the Djeno. Eni successfully completed a new production well in the Vandumbu field, 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06 offshore Angola. The VAN-102 well is being produced through the N'Goma FPSO and achieved initial production of 13,000 BOED. Production from this well and another well in the Mpungi field will bring Block 15/06 output to 170,000 BOED. Total started production from the ultra-deepwater Egina field in approximately 1600 m of water 150 km off the coast of Nigeria. At plateau, the field will produce 200,000 B/D. Total operates the field with 24% interest, in partnership with NNPC, CNOOC, SAPETRO, and Petrobras.
Africa (Sub-Sahara) Eni successfully completed a new production well in the Vandumbu field, 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06 offshore Angola. The VAN-102 well is being produced through the N'Goma FPSO and achieved initial production of 13,000 BOED. Production from this well and another well in the Mpungi field will bring Block 15/06 output to 170,000 BOED. Anglo African Oil & Gas encountered oil at the TLP-103C well at its Tilapia license offshore the Republic of Congo. The well intersected the targeted Djeno horizon, and wireline logging confirmed the presence of a 12-m oil column in the Djeno. Total started production from the ultra-deepwater Egina field in approximately 1600 m of water 150 km off the coast of Nigeria. At plateau, the field will produce 200,000 B/D. Total operates the field with 24% interest, in partnership with NNPC, CNOOC, SAPETRO, and Petrobras.
Nunez, Walter (OXY – Occidental de Colombia) | Del Pino, Jessica (OXY – Occidental de Colombia) | Gomez, Sebastian (Baker Hughes) | Rosales, Douglas (Baker Hughes) | Puentes, Juan (Baker Hughes) | Rivera, Hamilton (Baker Hughes)
The Oil and Gas industry in recent years have been a great challenge for operators and aervice companies as well. This situation resulted in great opportunities to find efficiencies that can enhancement production, avoid down times and optimize operation in Electric Submersible Pump Systems (ESP). Keeping this on mind, one of the main drivers is implement procedures that can extent ESP run life, and one of the key challenges is to identify any trouble that can impact ESP performance timely so it can implement solutions to avoid failures. The main objective was to develop a troubleshooting manual that could be used for any engineer to identify likely conditions that could be affecting negatively ESP performance and to implement solutions to minimize failure or damage beyond repair in ESP equipment. A jointly team composed by the operator and the service company developed a troubleshooting manual to the proper identification of likely conditions that could be impacting the production and performance of ESP systems. This was achieved using monitoring information, tear down evidence, setting configuration and building a database with all the information in order to group similar cases to identify the best ways to respond to any anomaly in ESP behavior. This procedure was implemented in the field that have an average of 450 active wells with 93% being ESP systems, by socializing it with all the parties that participate in ESP troubleshooting to guarantee a proper handling of any occurrence. The main purpose of the creation of this procedure was to avoid failures associated with ESP operation conditions that could result in early failure; this is measured with the Failure Index (IF) that means the number of average interventions in an ESP field related to the average number of active wells in the same period. The implementation resulted in awareness in all the personnel that when best practices are followed there are better chances of field KPI improvements and savings, in this case the Failure Index of the field was reduced from 0.4 to 0.18 attributed to technology and best practices implementation as well. 2 SPE-199091-MS This paper aims to present the most relevant analyzed cases, the procedures implemented and the results in FI after implementation as well of recommendations to any party interested in implement similar projects in their operations.
In this work the potential for gas production from two selected methane hydrate deposits which are situated offshore from Uruguay is assessed along with the validity of numerical simulations as a tool for analysis in this environment. Gas hydrates are crystalline solids formed by gas and water, in which gas molecules are accommodated within a solid water lattice in a cage-like structure. They form in thermobaric conditions of relatively high pressure and low temperature which in nature occur in permafrost and deep water sediment environments. Marine methane hydrates represent a huge potential as an unconventional gas resource and production tests have already been perfomed offshore Japan and China confirming the validity of depressuration as a method of production.
Available 3D seismic data was utilized for the identification of interesting areas for gas hydrate studies focused on resource exploitation allowing the acquisition of the corresponding architectural parameters. Due to the lack of well data at the selected locations, geological models and reservoir properties were defined based on published data from studies on analogue situations including data from the first production test performed offshore of Japan. Reservoir simulations were carried out to assess the response of selected prospects to depressurization induced dissociation.
Two prospects, interpreted as turbidite type deposits and located at 1850 m and 788 m of water depth, were selected for the modelling studies. The simulation of short term production tests of 60 days indicates average gas release rate values from 34 100 std m3/d to 6700 std m3/d for the deeper and shallower prospect respectively. The simulations were greatly affected by geometrical non-geological parameters like the proximity of model boundaries as well as type and level of discretization. We found that for finer discretization cases, the use of logarithmically distributed radial grid cells led to the existence of artifacts at early time on the gas release rate curves while the use of uniformly distributed radial cells results in more stable behaviour of the gas release rate. Several realizations of the geological models were used and sensitivity analysis was carried out regarding permeability and hydrate saturation. A longer term production regime (10 years) for a heterogeneous layered case was also simulated for the deeper prospect resulting in very useful average gas release rates of approximately 70 000 std m3/d, essential to satisfy gas requirements of Uruguay. We predict that only a few wells would be needed.
For the first time, reservoir simulation was applied for prospects in Uruguay and the gas release potential for marine methane hydrate deposits in the Southern Atlantic margin was assessed. Simulation results are encouraging. Additionally the results of this work at the identified prospects may be useful for site selection for any future campaign for gas hydrate exploration offshore Uruguay.
Ferro, Santiago (ANCAP) | Rodríguez, Pablo (ANCAP) | Tomasini, Juan (ANCAP) | Gristo, Pablo (ANCAP) | Blánquez, Natalia (ANCAP) | Conti, Bruno (ANCAP) | Romeu, Cecilia (ANCAP) | Marmisolle, Josefina (ANCAP)
Recently, it was announced the first oil recovered in surface onshore Uruguay, in Norte Basin. Additionally, operators and Uruguayan National Oil Company (ANCAP) have identified many prospects, which are almost ready to be drilled, at different water depths offshore Uruguay. Therefore, it is relevant to know the minimum volume of hydrocarbons contained in hypothetical conventional discoveries, necessary to make the projects economically feasible in the light of the new Open Uruguay Round fiscal regime, both onshore and offshore.
The prospective resources distribution was calculated for several prospects, which were identified with 2D and/or 3D seismic, and are located onshore and offshore at various water depths. The probabilistic cash flow analysis including forecasts for production, capital and operating costs, product prices and the new fiscal regime was conducted in all cases to define the breakeven oil prices and the Minimum Economic Field Size (MEFS). Finally, the Net Present Value, the probability of geological success and the probability of development were considered to complete the expected monetary value and the probability of commercial success calculations.
Many aspects can be taken away from this work. Firstly, as a general trend, the MEFS and the breakeven oil price required for the prospects increase with water depth, reflecting the rise in expenditures. However, specific prospect parameters may cause a separation from this clear trend. Likewise, the decision to sell or reinject natural gas has a significant influence on project profitability. Additionally, the probabilities of geological success, in the abscense of productive analogues in the south Atlantic, are still low in all cases, reinforcing the status of frontier exploration of the Uruguayan sedimentary basins. Hence, with the objective to overcome this weakness and encourage exploration, the minimum government take established in the new Open Uruguay Round regime is fairly low. In conclusion, projects onshore and offshore could be equally profitable and successful, requiring higher size of discoveries and price of products as water depth increases. However, because of the remarkable difference in investment and costs, onshore opportunities fit for smaller companies’ portfolios and ultradeepwater prospects are almost exclusive for the majors.
This paper presents new and useful information to geoscientists, engineers and managers of International Oil Companies (IOCs) evaluating exploratory projects in Uruguay, as it includes the novel fiscal regime in force. Finally, it proposes an innovative methodology to calculate the MEFS, breakeven oil prices and the probability of commercial success from the stochastic model.
Nunez, Walter (OXY – Occidental de Colombia) | Del Pino, Jessica (OXY – Occidental de Colombia) | Garzon, David (OXY – Occidental de Colombia) | Pinto, Duvan (Baker Hughes) | Gonzalez, Camilo (Baker Hughes) | Pinilla, Jaime (Baker Hughes) | Gomez, Alvaro (Baker Hughes)
In the Llanos Norte area, ESP systems represent 92% of the installed artificial lift systems. According to the current production strategy in this field, there is a need for intervention in low quality sand. The design of the artificial lift system is affected by the uncertainty of the productivity index and expected flow rates. 25% of the completions designed for low flows have had deviations greater than or equal to 50% between the design parameters and the actual parameters. This condition has led to the search for alternatives for intervention and completion of this type of wells, this because the conventional technology of the pumps used historically in the field does not allow producing efficiently in such a wide uncertainty production ranges.
Service Provider, from the hand of the Operator implemented a pump called FLEX-ER (extended range pump). This solution allows extending the range of the efficiency cone of the pump from 50BFPD and up to 2900BFPD, this feature helps to mitigate the uncertainty in the available design parameters, keep the pump in the optimal ranges of operation, avoid the up and down wear of the stages, thus increasing the lifetime of the electrosubmersible system.
The implementation of this technology has allowed having an ESP equipment available to cover the production needs of the wells in low quality sands of northern plains. The wide range of operation of this stage allows to be protected against uncertainty in productivity and facing the changes that the well may have during its production stage. Additionally, the implementation evaluation model for 8 wells resulted in a projected saving of USD 1.4 million, as a consequence of the reduction in intervention costs, energy consumption and NPT reduction. According to these results, it is expected for the next well drilling and reconditioning campaigns, including the standardization of the technology in order to optimize the production processes of Occidental.
This paper aims to present the most important technology implementations, follow up and results as well as the impact in field performance KPI.
Each edition of the Olympic Games brings together remarkable athletes, volunteers, and spectators of all nationalities in a long-anticipated competition. While Brazil just finished hosting its first summer Olympics in the coastal city of Rio de Janeiro, in the world of oil and gas megaprojects another type of competition is in play--that of market share. More akin to a marathon race than a sprint, Olympic-sized oil and gas megaprojects take years to come to fruition and require billions of dollars in development costs. Not every planned megaproject will make it to the finish line. What does it take for these ultraambitious projects to succeed?
This paper describes a trial project to evaluate autonomous inflow control device (AICD) technology to better manage water production in a large heavy oil field in Colombia. The Cajua block is part of the Rubiales field is in the Llanos basin of Eastern Colombia, and has reserves estimated at 7.5 billion barrels. One of the main production challenges is the high water cut, or BSW, driven by strong aquifer flow in the underlying sands of the Carbonera formation. Many wells experience early water break-through and must be produced above 95% BSW for long periods of time. Horizontal wells typically produce up to 8000 barrels per day of total fluid with electric submersible pump (ESP) on cold production, and do not utilize any thermal recovery methods. The loosely-consolidated sandstone reservoir has variable water saturation and permeability, which has continuously frustrated operators'’ attempts to manage water production ever since the Rubiales field was first brought online in the 1980's.
In late 2018, a three well pilot project was initiated to evaluate the ability of inflow control technology to manage water influx at the sandface of the horizontal completions. Three wells in the Cajua block were equipped with AICD screens and swellable packers to evaluate oil production and water cut. The AICD technology works by limiting water inflow based on fluid viscosity. Each segment, or compartment, of the horizontal wellbore is isolated by swellable packers, and the AICD creates a higher or lower drawdown on the reservoir depending on the fluid properties, favoring the inflow of high-viscosity heavy oil over the low-viscosity water.
The early production results show that AICD completions can effectively manage water production by delaying water break-through and restricting water inflow from the reservoir. Each of the three trial wells responded positively to the autonomous ICDs, allowing engineers to produce heavy oil wells more effectively with lower cumulative water volumes.
This project marks the first implementation in South America of AICD technology with rate-controlled production (RCP) valves to manage water production in a heavy oil field. It is also the second application worldwide, after Canada, to show that AICDs can effectively to manage water cut in a heavy oil, cold-production scenario.
Drilled by Seadrill’s West Gemini sixth-generation ultradeepwater drillship, the Agidigbo-1 NFW well reached TD of 3800 m in 275 m of water. Italian multinational firm Eni has made its fifth light-oil discovery on Block 15/06 in the deep waters off Angola through an exploration program it launched just last year. The Agidigbo-1 NFW well proved a single hydrocarbon column consisting of a 60-m gas cap and 100 m of light oil in Lower Miocene sandstones with good petrophysical properties, Eni said. Drilled by Seadrill’s West Gemini sixth-generation ultradeepwater drillship, the well reached TD of 3800 m in 275 m of water. Analysis of the results indicate between 300–400 million bbl of light oil in place, the operator said.