Moving their directional drillers into their Houston real-time remote operations centers has improved drilling efficiency for two of the top shale producers. This paper presents an interdisciplinary approach to the description of tectonic dislocations made on the basis of interpretation of seismic data, petrophysical analysis of well-logging data in horizontal wells, and inversion of a multifrequency propagation tool. This work presents a systematic geosteering work flow that automatically integrates a priori information and real-time measurements to update geomodels with uncertainties and uses the latest model predictions in a decision-support system (DSS). The use of intelligent software is on the rise in the industry and it is changing how engineers approach problems. A series of articles explores the potential benefits and limitations of this emerging area of data science.
This paper introduces a new core-analysis work flow for determining resistivity index (RI), formation factor (FF), and other petrophysical properties directly from an as-received (AR) set of core samples. This paper discusses a study undertaken to gain better understanding of nuclear magnetic resonance (NMR) characteristics of volcanic reservoirs with different lithologies. Is the Cloud Mature Enough for High-Performance Computing? Data volumes are growing at an exponential rate. How can high-performance computing solutions help operators manage these volumes?
With the purchase, the growing, privately-held Chrysaor Holdings will expand its UK North Sea production to 185,000 BOE/D. The state-run offshore company has found a gas and condensate field that holds an estimated 250 million BOE. The latest example of the offshore sector's march toward automated wellbore construction will take shape later this year in the North Sea. Just 2 months after issuing more than a hundred licenses, the Oil and Gas Authority begins the process again for a whole new set of blocks. The company announced it would “initiate the process” of marketing its UK Central North Sea fields as part of a portfolio review.
Africa (Sub-Sahara) An 816-mile 2D seismic acquisition program was completed on the Ampasindava block, located in the Majunga deepwater basin offshore northwest Madagascar. The data will provide improved subsurface imaging of the large Sifaka prospect and will potentially mature additional prospects in the Ampasindava block to drill-ready status. Sterling Energy (UK) holds a 30% interest in the Ampasindava production sharing contract, which is operated by ExxonMobil Exploration and Production (Northern Madagascar) (70%). Asia Pacific Production began on the Liuhua 19-5 gas field in the Pearl River Mouth basin in the South China Sea. The field is expected to hit peak production of 29 MMcf/D this year. China National Offshore Oil Corporation (100%) is the operator. Drilling began on the YNG 3264 and the CHK 1177 development wells onshore in Myanmar.
Africa (Sub-Sahara) Mazarine Energy has started a two-well drilling campaign in the Zaafrane permit in central Tunisia. The first well, Cat-1, has been spudded and is targeting the Ordovician interval at a planned total depth of 3900 m. Mazarine (45%) is the operator with partners ETAP (50%) and MEDEX (5%). Asia Pacific China National Offshore Oil Company (CNOOC) has made a natural gas discovery at its deepwater Lingshui 25-1 well, northeast of Ledong sag in the South China Sea's Qiongdongnan basin, where the average water depth is 980 m. The well was drilled to a depth of 4000 m and encountered 73 m of oil and gas pay. During a test, the well produced approximately 35 MMcf/D of natural gas and 395 BOPD. CNOOC holds full operated interest in the license.
Regueira, Teresa (Center for Energy Resources Engineering [CERE], Technical University of Denmark) | Sandoval, Diego (Center for Energy Resources Engineering [CERE], Technical University of Denmark) | Stenby, Erling (Center for Energy Resources Engineering [CERE], Technical University of Denmark) | Yan, Wei (Center for Energy Resources Engineering [CERE], Technical University of Denmark)
Confinement by tight pores can influence fluid phase behaviour according to some recent investigations. Most of these studies are theoretical and the experimental investigations are relatively scarce. In this work, we have employed the calorimetric approach to study the equilibrium of n-alkanes confined in two synthetic porous materials with a narrow pore size distribution, not only at atmospheric conditions but also at elevated pressures. In addition, we also measured two chalk samples from the Danish North Sea in order to shed light on whether the tight chalk formation will influence the phase behaviour. A shift in the saturation temperature of the confined fluids was observed when confined in the synthetic porous materials, whereas no temperature shift was observed in the fluid confined in the chalk powders. By using phase equilibrium calculation incorporating capillary pressure difference between the gas and liquid phases, we also predicted the temperature shifts and compared them with the experimental values.
The influence of porous media on phase behaviour is a topic discussed in the oil industries for decades with revived interests and investigations in recent years due to its potential impact on production from tight shale. For the tight chalk formation in the North Sea, a similar question on the role of porous media in phase behaviour has been frequently asked. Some recent experimental and modelling methods developed for shale may help answer the question.
The Lower Cretaceous chalks in the Danish Central Graben have porosities in the range from 15 to 45% with a very small average permeability, lower than 1 mD. The current production from these reservoir rocks in the Danish Central Graben happens in the Valdemar field, which is a very complex and heterogeneous reservoir with a low and uneven production (Jakobsen et al. 2005). It is expected that in this tight rock the reservoir fluids are subjected to a high degree of confinement. The interaction between the fluid and the pore wall is significant, and there is always a question whether the phase behaviour in the tight formation will be dramatically changed. In principle, the phase behavior of confined fluid can be altered due to large capillary pressure differences, selective adsorption, and extreme reduction in the free space of movement. These effects result in changes of fluid physical properties and shifts in saturation pressures/temperatures. When such differences are taken into account into reservoir simulation studies, well performance, gas-oil ratio, oil and gas production rate, and ultimate recovery may be affected. (Wang et al. 2014, Teklu et al. 2014, Dong et al. 2016, Firincioglu et al. 2012)
The Slootdorp field has a complex structure with most reserves in Rotliegend sandstone, which is communicating with gas bearing Zechstein carbonates. The Rotliegend reservoir is bounded by a large fault, which might become seismogenic during depletion. A 3D geomechanical model was built, based on the faults and horizons in the geological model. Both the Rotliegend and Zechstein reservoirs were included in the model. The model was populated with geomechanical properties derived from logs, LOT's (leak off tests) and regional data on the stress field. Also, overburden properties from previous studies on nearby fields were used.
The pressure input was obtained from reservoir simulation. It is important to include the water leg pressure in the pressure input since the Rotliegend gas reservoir is in contact with an active aquifer. Pressure reduction drives the compaction of the reservoir, which induces stresses on the faults causing slippage. Since the water is quite incompressible, a large pressure reduction in the water leg may be caused temporarily by a rising gas water contact.
It turned out that slippage is not expected at the lowest gas pressure using a conservative estimate of the critical friction coefficient on the fault of 0.55. Sensitivity analysis on the most important input parameters was performed with a range that can be expected for such a field. The result was that the maximum critical stress ratio could range between 0.46 and 0.53 for the expected uncertainty of input parameters. The geomechanical modeling shows that an active aquifer has a dominant, mitigating effect on seismic risk, which can explain why many reservoirs show no seismicity in the Netherlands, although other effects could also play a role.
Hwang, Jongsoo (The University of Texas at Austin) | Sharma, Mukul (The University of Texas at Austin) | Amaning, Kwarteng (Tullow Ghana Limited) | Singh, Arvinder (Tullow Ghana Limited) | Sathyamoorthy, Sekhar (Tullow Ghana Limited)
Understanding injectivity is a critical element to ensure that sufficient volumes of water are being injected into the reservoir to maintain reservoir pressure, to ensure good reservoir sweep and minimize well remediation. It is, however, challenging to describe the large injectivity changes that are sometimes observed in injectors operating under fracturing conditions. This study presents a field case study with the following objectives: 1) explain the complicated injectivity changes caused by fracture opening/closure with injection-rate variations, 2) define a safe operating envelope (for injection pressure and rate) that ensures fracture containment and injection into the target zone, and 3) prescribe how the injection rate should be changed to achieve higher injectivities. Injector operating conditions are developed using results from a full 3-dimensional fracture growth simulation to ensure fracture containment in a multi-layered reservoir.
We present field injectivity observations, a comprehensive simulation workflow and its results to explain injector performance in a deep-water turbidite sand reservoir with multiple splay sands. Understanding the impact on fracture propagation and containment allows us to make quantitative suggestions for the operating envelopes for long-term injection-production management. Strategies for high-rate injection to sustain the injection well performance long-term are discussed.
Simulation results show that, at injection rates over 5,000 bwpd, injection induced fractures propagate. Fracture closure induced by injection shut-down is used to compute the bottom-hole pressure decline as a function of time. The fracture opening/closure events and the thermally induced stress were the primary factors impacting injectivity. The simulation results suggested several ways to improve the injectivity while ensuring fracture containment. Injection under fracturing conditions into a single zone at a high rate is shown to be feasible and this allows us to support a substantial increase in injectivity. This must, however, be done at pressures that will not cause a breach in the bounding shales. The 3-dimensional fracture simulations identified the operating pressure and rate envelope to maximize the injection rates while minimizing the risk of breaching the cap rock and inter-zone shales.