The acquisition of downhole pressure data representative of reservoir response enabling subsequent pressure transient analysis has been one of the primary drivers for running drill stem tests. However, many factors can influence the representativity and interpretability of the data acquired that are not related to reservoir properties.
To our knowledge, while many publications have presented challenges in acquiring representative pressure data those have not been compiled in a comprehensive revies, and there are no practical recommendations that would summarise causes and effects and offer procedures to eliminate or at least manage those effects and enable end-users to maximize the value of acquired data.
This paper describes in details today's challenges associated with the acquisition of high-quality, representative and undisturbed bottom hole pressure data during well test operations. Many different effects, including gauges’ deployment methods, wellbore effects and operational aspects of the test can compromise the quality of bottom hole data acquired while running a welltest.
Therefore, the origin and impact of each of these effects needs to be evaluated at the design stage of the test to develop appropriate mitigation actions. To address these issues, actual examples and methodologies derived from various locations are presented.
Over the years the metrological performances of downhole memory gauges such as resolution or drift have improved drastically, reaching a point where gauge specifications have become less influential on data quality than environmental effects. Many improvements have also been made in DST tools to increase the representativity and interpretability of acquired bottom hole pressure data such as the introduction of downhole shut-in valves or compensation for tubing contraction and expansion due to temperature change during the test. However, there remain several occurrences today where memory gauge data are affected by the various wellbore phenomena making interpretation of downhole pressure transient test data complicated. The selection of an appropriate location of pressure sensors in the DST string also remains a crucial task.
The paper provides analysis, explanations and practical recommendations allowing to mitigate the most common effects typically observed during welltest operations performed around the world, such as: Tidal effect Fluid segregation effect in the wellbore Pressure noise propagation from the surface due to rig movement The impact of application of electrical submersible pump (ESP) on the quality of pressure build-up data "Hammer effects" during well shut-in Impact of circulation above the test valve during PBU Impact of pressure bleed off and top up in the annulus Fluid cooling effect in the wellbore Gauge movement due to string contraction and expansion
Fluid segregation effect in the wellbore
Pressure noise propagation from the surface due to rig movement
The impact of application of electrical submersible pump (ESP) on the quality of pressure build-up data
"Hammer effects" during well shut-in
Impact of circulation above the test valve during PBU
Impact of pressure bleed off and top up in the annulus
Fluid cooling effect in the wellbore
Gauge movement due to string contraction and expansion
This paper will summarise the observation and lessons learned from hundreds of welltest operations performed around the globe with different reservoir fluids and environments through a few telling examples. Furthermore, the paper provides practically proven well-test techniques allowing to manage those adverse effects on bottom-hole pressure data. Recipes for success are provided to ensure that high-quality data can be acquired during welltest operations in a challenging environment while keeping the cost in line with the AFEs.
Gas injection is a proven EOR method in the oil industry with many well-documented successful field applications spanning a period of more than five decades. The injected gas composition varies between projects, but is typically hydrocarbon gas, sometimes enriched with intermediate components to ensure miscibility, or carbon dioxide in regions such as the Permian Basin, where supply is available at an attractive price.
Miscible nitrogen injection into oil reservoirs, on the other hand, is a relatively uncommon EOR technique because nitrogen often requires a prohibitively high pressure to reach miscibility. Unlike other injection gases, the minimum miscibility pressure for nitrogen decreases with increasing temperature. In fact, in deep, hot reservoirs containing volatile oil, nitrogen may develop miscibility at a pressure similar to the MMP for hydrocarbon gas or carbon dioxide. The phase behavior is more complicated than what can be captured by correlations and hence requires equation-of-state calculations.
Results from a recent EOR screening study in ADNOC indicate that a couple of high-temperature oil reservoirs in Abu Dhabi may be potential targets for miscible nitrogen injection. This paper discusses key aspects of the EOS modeling. Advanced gas injection PVT data are available to enable a fair comparison between nitrogen, carbon dioxide and lean hydrocarbon gas. In this work, we have modelled and analyzed the phase behavior of two volatile oil systems with respect to nitrogen, hydrocarbon gas, and carbon dioxide injection, as part of a reservoir simulation study, which will be covered in a subsequent publication; see
Waterflooding is the main technic to recover hydrocarbons in reservoirs. For a given set of wells (injectors and producers), the choice of injection/production parameters such as pressures, flow rates, and locations of these boundary conditions have a significant impact on the operating life of the wells. As a large number of combinations of these parameters are possible, one of the critical decision to make is to identify an optimal set of these parameters. Using the reservoir simulator directly to evaluate the impact of these sets being unrealistic considering the required number of simulations, a common approach consists of using response surfaces to approximate the reservoir simulator outputs. Several techniques involving proxies model (e.g., kriging, polynomial, and artificial neural network) have been suggested to replace the reservoir simulations. This paper focalizes on the application of artificial neural networks (ANN) as it is commonly admitted that the ANNs are the most efficient one due to their universal approximation capacity, i.e., capacity to reproduce any continuous function. This paper presents a complete workflow to optimize well parameters under waterflooding using an artificial neural network as a proxy model. The proposed methodology allows evaluating different production configurations that maximize the NPV according to a given risk. The optimized solutions can be analyzed with the efficient frontier plot and the Sharpe ratios. An application of the workflow to the Brugge field is presented in order to optimize the waterflooding strategy.
Tyrie, Jeb (Bridge Petroleum) | Mulcahy, Matt (Bridge Petroleum) | Leask, Robbie (Bridge Petroleum) | Wahid, Fazrie (Bridge Petroleum) | Arogundade, Olamide (Schlumberger) | Khattak, Iftikhar (Schlumberger) | Apena, Gani (Schlumberger) | Samy, Mohammed (Schlumberger) | Sagar, Rajiv (Schlumberger) | Xia, Tianxiang (TRACS International) | Nyadu, Kofi (WorleyParsons, Advision) | Maizeret, Pierre-David (Schlumberger)
This paper describes the proposed re-development of the Galapagos Field, comprising the abandoned NW Hutton field and the Darwin discovery (Block 211/27 UKCS) which forms a southerly extension. The paper covers the initial concept and analytical evaluation, the static uncertainty model build, the dynamic model history-match, the iterations between static and dynamic modelling, the development subsea and well locations, the optimisation workflow of the advanced Flow Control Valve (FCV) completions in both producers and injectors and the facilities constraints.
The redevelopment plan involved several multi-disciplinary teams. 20 years of production data from 52 wells were analysed to identify the production behaviour and confirm the significant target that provided the basis for the development concept selection. The full Brent sequence compartmentalised stochastic static model was based on reprocessed seismic plus 14 exploration and appraisal wells. Streamlines, uncertainty sensitivities and mostly good detective work honed a history match to RFT, BHP, PLT and oil and water production. P50, P90/P10 models were selected and over 100 FCVs optimised to deliver the profiles against an identified FSPO facilities’ constraints.
Over 1,000 static models were delivered consisting of sheet sands, incised valleys and channels in heterolithic facies overprinted by a depth trend with appropriate uncertainty ranges. The high well count gave a tight STOIIP probabilistic range of 790/883/937 million stb. The early RFTs illustrated extreme differential depletion between Brent zones and subzones of the Ness. To history-match these the dynamic model retained the static model definition in the Upper Ness to capture the thin but extensive shales. The early 18-month depletion and the late steady production-injection phases were simulated separately in prediction mode and matched the Production Analysis estimated ‘future’ production giving confidence to the history matched model. The initial concept development of 4 subsea-centres, to cover the large field area, with an injector in each compartment proved a robust selection. The horizontal wells increase PI where needed and mitigate internal faulting. The optimisation of the FCVs significantly increased oil production from all zones and drastically reduced water injection and production so that the identified FPSO modifications were relatively modest. The final First Stage Field Development Plan consists of 11 producers and 6 injectors across developed and undeveloped areas confirmed robust P50 reserves of 84 million boe.
Robust concept selection allowed for early identification of production units so that constraints and modifications could be accounted for within the economic model.
The Galapagos field re-development plan is an excellent example of how detailed static and fully history matched dynamic models can lay the foundations for new technology like the optimisation of the FCVs to access bypassed reserves using significantly smaller production units with reduced requirements for power, compression, gas lift, pumping pressure, injection and production. In short, they shrank the facilities.
This paper presents an overview of the SACROC Unit’s activity focusing on different carbon dioxide (CO2) injection and water-alternating-gas (WAG) projects that have made the SACROC unit one of the most successful CO2 injection projects in the world. Several studies explored the possibility of improving both areal and vertical sweep efficiency in mature water-alternating-gas (WAG) patterns in the Magnus oil field.
The strategy supports the Maximise Economic Recovery from UK Oil & Gas Strategy and Vision 2035, whose goal is to achieve £140 billion additional gross revenue from UKCS production by that time. The round marked a continuation of a recent trend on the UKCS in which lesser-known firms and newcomers have gained stature, replacing more-familiar, bigger operators that have pared down their North Sea positions. Some 3,000 people and counting intrigued by UK oil and gas data have signed up for access to the country’s new National Data Repository. What motivated the OGA to make the data available to the public, and what can the public do with the data? A recent spike in production has engendered a cautiously optimistic outlook for the UKCS, but will it do anything to stave off the overall decline of the mature basin?
Anchored by the Khaleesi-Mormont and Samurai fields, the King’s Quay FPS will receive and process up to 80,000 B/D of crude oil. UK operator Trident Energy is entering Brazil while Australian firm Karoon Energy is expanding its position in the country. Both will try to boost output from already-producing assets. The world’s largest oil producer has awarded $18 billion in engineering, procurement, and construction contracts as part of its Marjan and Berri expansion projects. The Norwegian operator will increase its ownership of the giant Johan Sverdrup field before the field commences oil production this November.
Australia’s BHP Billiton and the recently acquired Anadarko Petroleum submitted the largest dollar totals of high bids in US Gulf of Mexico Lease Sale 253. Moving their directional drillers into their Houston real-time remote operations centers has improved drilling efficiency for two of the top shale producers. In its first 50 years, LNG has become the world’s fastest-growing gas supply source and is now part of an upheaval in the global energy market. Today, the sector stands at a crossroads, and the industry must adopt new thinking to address current and future needs of buyers, sellers, and consumers. The new well control rule is evidence that memories of the Macondo blowout remain a powerful force for caution.
Bravo is the second of four platforms to be decommissioned and removed from the Brent field, following Brent Delta in 2017. The field has produced approximately 3 billion boe since 1976. A panel of UK government officials and industry executives discuss opportunities to increase efficiency in North Sea decommissioning programs.
The subsea tieback is expected to start up in 2021. This is Shell’s second major development on a tieback in the US Gulf of Mexico, following Kaikias’ startup in May. Bravo is the second of four platforms to be decommissioned and removed from the Brent field, following Brent Delta in 2017. The field has produced approximately 3 billion boe since 1976. First cargo from the world’s largest floating LNG project comes in the midst of low LNG prices sparked by a global supply boost.