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Africa (Sub-Sahara) Aker Energy, as operator of the Deepwater Tano Cape Three Points (DWT/CTP) block, encountered oil in the Pecan South-1A well offshore Ghana. Total volumes are estimated at 600 million–1 billion BOE. Aker Energy has a 50% participating interest in the block. Partners are Lukoil (38%), Ghana National Petroleum Corporation (GNPC) (10%), and Fueltrade (2%). Eni announced a discovery at the Agogo‑1 NFW well in Block 15/06 in the Agogo exploration prospect offshore Angola. The discovery, in 1636 m of water, is estimated to contain 450–650 million bbl of light oil in place. Eni owns a 36.8421% stake in the Block 15/06 joint venture.
Take Back Control of Your Capital Project with an EPC 4.0 Strategy Stratigraphical - Sedimentological Framework For The Thamama Group Development In The Western Uae Based On The Legacy Core Data: How The Key To The Future Is Found In The Past. Performance Comparison Of Two Different In-house Built Virtual Metering Systems For Production Back Allocation. Innovation In A Time Of Crisis: How Can The Upstream Industry Develop New, Fit-for-purpose Technology? How To Meet Operational Challenges In An Extreme VUCA Environment By Adaptive Process Control. Challenges In Drilling & Completion Of Extended Reach Drilling Wells With Landing Point Departure More Than 10,000ft In Light/ Slim Casing Design.
Liu, Hongtao (PetroChina Tarim Oilfield Company) | Wang, Haotian (University of Texas at Austin) | Zhang, Wei (PetroChina Tarim Oilfield Company) | Liu, Junyan (PetroChina Tarim Oilfield Company) | Zhang, Yutao (Chengdu Zhongpu Oil & Gas Technology Co., Ltd.) | Sharma, Mukul M. (University of Texas at Austin)
Sand production has been a very serious concern for the high-pressure, high-temperature (HPHT) gas wells in the Tarim Basin. However, the possible reasons and mechanisms remain unclear because there is no sufficient model to predict both onset of sanding and sand-production rate. The objective of this study is to develop a three-dimensional (3D) numerical sand production-prediction model and apply it to these HPHT gas wells to determine the main mechanisms for sand production and to propose completion designs to minimize sand production. This paper presents the development of a fully coupled 3D, poro-elasto-plastic sand-production model and the simulation results for two key wells that are prone to sanding.
The sand-production model was used to model the different completion designs and flowback strategies that were used in the field. The model couples multiphase fluid flow and elasto-plasticity to simulate pressure transient behavior and rock deformation during production. The sanding criterion is a combination of both mechanical failure (shear/tensile/compressive failure) and fluid erosion. A novel cell-removal algorithm has been implemented to predict the dynamic (time dependent) sand-production process. In addition, the complex geometry of the wells and perforations are explicitly modeled to show cavity propagation around hole/perforations during sand production.
For this case study, triaxial tests on core samples were conducted, and the stress-strain curves under different confining stresses are analyzed to obtain rock properties for both the preyield and post-yield period. The wells were categorized into ones that had massive sand production and ones that showed much less sand production. Operational and mechanical factors that were empirically found to result in sand production were identified. The sand-production model was run to verify the role played by different factors. It is shown that completion design, rock strength, and post-failure behavior of the rock are key factors responsible for the observed sanding in these wells. In addition, the drawdown strategy and the associated bottomhole pressure (BHP) change and the extent of depletion play an important role in the sanding rate. Several strategies for minimizing sand production are suggested for these wells. These include drawdown management, completion, and perforation design. In this study, we show for the first time that data from HPHT gas wells that have severe sand-production problems can be analyzed quantitatively with the developed model to determine the mechanisms of sand production. This allows us to make operational recommendations to minimize sanding risk in these wells.
An anticipated acceleration in LNG's commoditization, driven by factors such as increased natural gas demand and newfound confidence in its potential as a marine fuel and as the cleanest of the fossil fuels, having lower emissions than either coal or oil fired power generation is expected to hand it a much larger role in global energy markets. The deployment floating liquefied natural gas (FLNG) facilities, becomes increasingly important as an option to achieve this task rather than an onshore facility. Jettyless LNG transfer concept could cut total project cost by 50%.
Recent policies in Europe have encouraged the use of renewables, with gas being the obvious complementary source of energy for power generation when these intermittent sources need backup power. A supply chain is the network of LNG from the upstream to the downstream called a distribution channel have three main flows which are the product, information and the finances flow. FLNG is an emerging technology for such fast and cost effective development of technology to unlock smaller, remote or environmentally sensitive fields. LNG Monetization will be thoroughly examined. FLNG however present some novel challenges less on the technical side and more to do with the supply chain, project management, stakeholder engagement, financing, regulation and tax. Understanding regulatory, legal, financing tax issues and engaging with the relevant stakeholders well ahead of investment decisions are keys. Flexibility is also being introduced in LNG Import Terminals, which have the potential to serve as a LNG Hub where LNG is received in bulk volumes from an LNG carrier and is then distributed out through gas pipeline. This solution is applicable when the visiting LNG carrier is connected to the onshore storage without a jetty. This solution enables small-scale LNG transfers to the LNG storage on shore or to the landlocked Floating Storage and Regasification Units. The international natural gas sector was geographically divided into distinct regional markets. The US and Europe supplied mainly by pipelines and Asia supplied by LNG. For all regions, there is a striking difference between the geopolitical context of international pipeline gas business and LNG which will be detailed in this work. The FSRU is lower in cost and can be reused while the land based terminals cannot be relocated. Geopolitics is a central concern for the oil and gas sector and can be viewed as a source of both risk and opportunity as identified by EY. Collaboration in adding values to the LNG business measured by total revenue will be examined in the work.
Berger, William Bill J. (Berger Geosciences, LLC) | Metz, Zachary Ian (Berger Geosciences, LLC) | Gao, Baiyuan (Berger Geosciences, LLC) | Przybylski, Piotr Antoni (Berger Geosciences, LLC) | Bisrat, Shishay (Berger Geosciences, LLC) | Jere, Chaitanya B. (Berger Geosciences, LLC) | Deshpande, Asim A. (Berger Geosciences, LLC)
Extending the geohazards assessment throughout the overburden section above the main reservoir is a relatively recent practice. Traditionally, a geohazards assessment for the riserless section of wells has been a key element of pre-drill studies in offshore well planning. Potential geohazards such as seafloor/buried faults, gumbos, gas hydrates, shallow gas and shallow water flow are routinely investigated using seismic reflectors, seismic amplitude, extent of well-known problematic stratigraphic units, and offset wells drilling data. As a result, the understanding of the regional distribution of geohazards has increased significantly.
Although the common geohazards as mentioned above are well known, the assessment has been challenging with deeper depths. The loss of seismic resolution with depth affects the interpretation of the stratigraphy, structure, pore pressure and fracture gradient. The uncertainty in the depth and inclination of key marker events including stratigraphic horizons, chronostratigraphic ties, etc. might lead to a wide margin of possible pore pressure and fracture gradient (PPFG) estimates. The velocity-effective stress transformations used for pre-drill PPFG from low resolution seismic data is also less reliable, compounding the error resulting from predicted stratigraphic markers (horizons). Seismic interpretations with low resolution are inadequate to identify thin over-pressured zones.
The paper presents an integrated workflow that maximizes the predictability of geohazards for the entire reservoir overburden section. A variety of seismic volumes including amplitude reflection, amplitude versus offset (AVO), seismic inversion, seismic velocity, coherence data, etc. allows for the optimization of interpretations such as stratigraphy, structure, and rock properties. A detailed geologic model with advanced seismic processing techniques provides a high-resolution understanding of structure and stratigraphy, seismic attribute distributions, and spatial velocity variations. The model is useful to identify key faults, leak points, sealing intervals, and trapping mechanisms. Understanding the stratigraphic facies assists in mapping the intervals of pressure generation and retention zones. Considering these limitations, offset well data is integrated when available and utilized to characterize seismic facies and rock properties in sparse data environments. These data are then correlated with seismic reflection and velocity data to develop a well-constrained geologic model. Multiple types of seismic volumes with various frequencies, coverages, and penetration provide better control and understanding of the riserless section. This may include AVO and inversion volumes, which are not commonly used in a shallow geohazards assessment. Finally, a fully integrated geohazards assessment, from the seafloor to the main reservoir, results in an optimized drilling program and is developed to minimize the impact of geohazards and drilling risks along the wellbore trajectory.
Kumar, Rajeev Ranjan (Schlumberger) | Mukherjee, Sanjay (ONGC) | Bhagat, Jayant (ONGC) | V, Rajasekar (ONGC) | Bhuskute, Akshay (ONGC) | Bandyopadhyay, Bidesh (ONGC) | Talreja, Rahul (Schlumberger) | Singh, Manish (Schlumberger) | Subbiah, Surej Kumar (Schlumberger)
With known basement hydrocarbon accumulation, Mumbai High field in Western Offshore, India is a priority area for extending the concept of geo-mechanical fracture characterization in metamorphic basement reservoirs. Basement in Mumbai High is hydrocarbon bearing in areas proximal to major fault zones and intersections of major regional tectonic cross trends. Basement reservoirs have always been a challenge considering the lateral variation in rock properties with varying stress profile. The field under study has few wells producing hydrocarbon from varying depth intervals within Basement. Considering lower ROP, higher drilling cost and varying stress azimuth, a study has been conducted covering 3D Geomechanical numerical simulation and discrete fracture network stability analysis to identify sweetspots for new well locations targeting basement reservoirs while history matching field observations in offset wells. Basement reservoirs are often characterized by fracture sets which are conduit at present stress regime in far field condition. Some fracture sets are aligned within 20deg-30deg to maximum horizontal stress azimuth with few to be 90deg away from the maximum horizontal stress azimuth. To capture variation of fracture stability at field level, an analysis has been conducted at each offset well location, where geophysical logs, drilling parameters and geological information are integrated to construct a Mechanical Earth Model (
Reliance's Jamnagar refinery in Gujarat, India is the largest in the world. Gujarat is a state on the western coast of India with a coastline of 1,600 km (990 miles) and population in excess of 60 million. It is the fifth largest Indian state by area and the ninth largest by population. It encompasses the entire Kathiawar Peninsula (Saurashtra) as well as the surrounding area on the mainland. The capital of the state, Gandhinagar, is on the outskirts of the north-central city of Ahmedabad, which was the former capital, the largest city in the state, and one of the most important textile centers in India.
Wang, Bo (China University of Petroleum-Beijing at Karamay, Xinjiang) | Zhou, Fujian (China University of Petroleum, Beijing) | Yang, Chen (North China University of Water Resources and Electric Power) | Wang, Daobing (Beijing Institute of Petrochemical Technology) | Yang, Kai (China University of Petroleum, Beijing) | Liang, Tianbo (China University of Petroleum, Beijing)
Temporary plugging and diverting fracturing (TPDF) has become one of the fastest-growing techniques to maximize the stimulated reservoir volume (SRV). During the field operation of TPDF, diverters are injected to redirect the hydraulic fractures into the understimulated region of the reservoir, and, thus, to obtain better coverage of the created fracture network. In this study, the commonly used true tri-axial hydraulic fracturing system is modified to investigate the influences of various factors on the injection pressure response and resultant fracture geometry during diversion treatments. The experimental results show the feasibility of creating multiple fractures through TPDF, and more importantly give the following findings: (1) a complex diverted fracture network tends to be created at a small differential stress (2.5 MPa in this case), while diverted fractures tend to grow parallel to the initial fractures at a high differential stress (7.5 MPa in this case); (2) with the same concentration in the fracturing fluid, 40-mesh powder-shaped diverters can plug the created fractures and increase the net pressure more rapidly than 6-mm fiber-shaped diverters; (3) an excess of diverters can lead to a strong injection pressure response, and, thus, enhance the difficulty of creating multiple fractures; (4) when diverters are injected with the fracturing fluid, no obvious breakdown pressure or propagation pressure is shown during the fracture propagation.
This paper demonstrates that data-driven approach can address to resolve the big data complexity, enhance reservoir characterization and accelerate history matching process into an offshore mature field with many challenges such as complex reservoir geology with high properties variation, fair correlation between seismic amplitude and reservoir properties, multi-stacked completion of production/injection strings, commingled production system from multiple zones, mechanical leaking issue and sparse production allocation.
By these complexities, classical technique of integrated full-field modelling cannot be done easily. In addition, it is difficult to acquire reservoir engineering insights for reservoir characterization. Data-driven reservoir modelling approach is applied to tackle the technical challenges. A workflow is proposed for rapid quality check of big data and integrated with systematic reservoir engineering analyses. In data-driven approach, current understanding of geology and physics is relieved with field measurements data as the foundation of constructing the model. The model is kept at high level and introduce further detail where needed within the bound of uncertainty to achieve history match.
Data-driven approach has successfully improved reservoir characterization and provide cost-effective technique to accelerate history match process. The quality of big data (i.e. pressure, correct production allocation of each zone) plays key role in data-driven approach. Through early valuable insights from engineers, it significantly reduced the iterations number for history match purposes between engineers and geologist. In this study, it cuts from commonly in months to be weeks. Consequently, field-level and well-level history match can be satisfactorily achieved with deviation within 5%. The blind testing has been conducted to validate data-driven approach and improve confidence level with the model for further field development opportunities such as waterflood optimization, stimulation, new well placement, effective completion and enhanced oil recovery.
The results can be reconciled with geological understanding, which will be very useful and suitable in current oil price situation as a cost-effective technique, especially for mature fields with large data and have complexity in geological and production system. The data-driven approach can be deployed to other neighbour mature fields and can improve the level of confidence to support fast business decisions.
Drill cuttings are a valuable source of information about lithology and wellbore condition. Although an abnormally high number of cuttings would indicate some sort of failure at the wellbore wall, a detailed analysis of cuttings can help to identify the type of rock failure. Cavings, fragments that are relatively larger and of different shape compared to normal cuttings, can be used to decode critical information about the wellbore geometry and formation pressure.
Cuttings analysis is most useful in absence of direct indicators of wellbore condition such as caliper, image logs, or logging-while-drilling (LWD) data, but even in presence of such data, cuttings analysis can be used to corroborate the interpretations with direct measurements. Several mechanisms, such as underbalanced drilling, pre-existing weak planes, stress relief, or even the drilling process itself, can lead to production of cavings. Examining the cavings to interpret wellbore instability and mechanisms responsible for it is an expert's job and requires a good overall understanding of the prevailing geology, geomechanical principles, drilling procedure, and drilling tools.
Identification of wellbore failure during drilling provides a better chance of immediate remedial action, even before a wireline logging program is executed. Differentiating cuttings generated by the drill bit from cavings created by the wellbore failure is not an easy and straightforward task due to a variety of bits and phenomena involved in the generation of cuttings. The first step in this analysis is to broadly define the different types of cavings based on their shape and size. Then, we move to the basic key features of these cuttings, and, finally, provide the remedial action plan for each type.
Drill cuttings analysis was successfully applied to improve hole condition in real time for two wells drilled in the Western Offshore basin, India. One case study illustrates the importance of mud chemistry over the mud weight being used to drill. The second case study underscores the interpretation of shear failure as the reason for cavings from cuttings morphology analysis. In both the cases, timely intervention integrated with the identification of prevailing drilling issues in real time helped in understanding the mud system and its effects on the wellbore.
The novelty of this approach lies in the deep understanding and geomechanical application of cavings in providing timely and cost-effective recommendations to optimize drillability in both the presence and the absence of LWD data. The results can be used during the well-planning stage of future wells and during drilling to improvise mud chemistry or to identify required increase in mud weight to avoid breakouts related to chemical instability or shear failure even though the pore pressure profile may not necessarily require any further increase in the mud weight.