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) 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)
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.
Nielsen, Julie (The Danish Hydrocarbon Research and Technology Centre, Technical University of Denmark) | Poulsen, Kristoffer G. (Department of Plant and Environmental Sciences, University of Copenhagen) | Christensen, Jan H. (Department of Plant and Environmental Sciences, University of Copenhagen) | Solling, Theis I. (Center for Integrative Petroleum Research, College of Petroleum Engineering & Geoscience, King Fahd University of Petroleum and Minerals)
Mature fields often times surprise with respect to the production from the various wells across reservoir sections. This is for example the case in a tight chalk field that we have used as a case study for newly developed technique that employs oil finger printing in the analysis of production data. A small subset of wells has been found to produce significantly better than the remainder and we set out to explore whether the root cause is that there is a connection to higher lying reservoir sections through natural or artificial fractures. This was done with advanced analytical chemistry (GC-MS) and a principal component analysis to map differences between key constituents of the oil from wells across the reservoir section. The comparative parameters are mainly derived from biomarker properties but we also developed a way to directly include production numbers. The approach provides means to correlate the molecular properties of the oil with the production and the general composition that determines density and adhesive (to the rock) properties. Thus, the results provide a new angle on the flow properties of the oil and on the charging history of the reservoir. It is clear from the analysis that the subset of wells does not produce better because of a connection to an upper reservoir section that contributes to the production with oil of a different composition because the molecular mix is indeed quite similar in each of the investigated wells. It is not possible to rule out that there is a connection to an upper-lying section with oil from the same source. One aspect that does differs across the field is the ratio of heavy versus light molecules within each group of molecules and the results show that the region that produce better has the lighter components. We take that to indicate that the lighter components come from oil that flows better and thus is produced more easily. The reservoir section with the lighter oil also lies higher on the structure and is therefore must likely to have been charged first so part of the favorable production seems to be a matter of "first in" "first out". A GC-MS approach such as the one proposed here is cost-effective, fast and highly promising for future predictions on where to perform infill campaigns because the results are indicative of charging history and flow properties of the oil.
Deepwater drilling and production has been in existence for decades, and with it, stationkeeping philosophies and technologies have evolved with time and experience. In years past, moorings were designed purely with robustness and simplicity in mind, dropping anchors as rigs arrived on location, with the expectation to weather the storms, but now, with increased strengths seen in tropical rotating storms (TRS), ice floes, and deeper operating water depths, more sophisticated mooring components have been developed. Chain has yielded ground to wire and synthetic ropes. Stockless anchors have been replaced with piles, gravity installed anchors, and sophisticated high holding capacity (HHC) drag anchors. The connecting hardware has become “smart,” evolving from kenters and c-links to sensor and sonar-equipped remotely releasable systems.
The main drivers for this evolution have been environmental – extreme metocean events, corrosion, wear and fatigue – from the floater to the seabed and below.
This paper will present how “dumb steel” mooring systems have evolved into sophisticated and detailed engineered foundations that span miles of ocean real-estate, while allowing for a new level of vessel mobility that reduces risks to people and assets.
Yu, Hongyan (Northwest University) | Zhang, Yihuai (Curtin University) | Lebedev, Maxim (Curtin University) | Wang, Zhenliang (Northwest University) | Verrall, Michael (CSIRO) | Iglauer, Stefan (Edith Cowan University)
Carbon dioxide (CO2) inject to the saline aquifers are general considered as the best candidates for large-scale storage and CO2 enhance oil recovery. The pore structure and permeability are changed by the fines release, migration in the initial stage of CO2 injection, which is of great importance for reservoir screening and injection design requires adequate understanding. We thus imaged an unconsolidated sandstone at reservoir condition before and after live brine injection in situ with micro-CT core flooding apparatus. We conclude that the pore structure of the unsolid high pores media rock can be significantly changed after live brine injection, although the porosity just have a small increased. Meanwhile, many fractures are generated in the quartz after live brine flush away. Specific surface area are quantified from micro CT scan image analysis to calculate the absolute permeability. The permeability is significantly improved due to the pore structure change which can improve CO2 infectivity, especially low-permeability reservoirs. The results of this study present a broad characterization of the mechanical properties in lacustrine shale and can therefore help optimize hydraulic fractured fundamental and enhanced gas recovery.