bluuebunny/crossref_metadata_2025_split huggingface dataset:
Penetration Performance of a Shaped Charge Perforator in Sandstone and Limestone Targets at Extreme Pore Pressures and Constant Effective Stress
Authors: Haggerty D. , McGregor J. , Barker J. , Manning D. , DeHart R. 
Published: November 2016

Abstract
As the oil and gas industry expands perforating operations into higher-pressure environments, it becomes necessary to understand the effects of these higher pressures on the penetration capability of shaped charge jets. This paper discusses an investigation wherein penetration effects of shaped charge perforators were studied in both sandstone and limestone at ultrahigh pore pressures up to 32,000 psi under constant 10,000 psi effective stress in a laboratory environment. Sandstone and limestone cores were configured into targets guided by API RP 19B Section 2 methodology (2006). A specific shaped charge was selected to shoot in these targets with the only variable being the pressure conditions of the tests. These configurations consisted of oil-saturated cores with pore pressures ranging from 2,000 to 32,000 psi under a constant effective stress of 10,000 psi. High-resolution computed tomography (CT) scan images were not only used to measure an accurate penetration depth and perforation tunnel dimensions, but also to provide a 3D view of the resulting perforation tunnel for qualitative analysis. Penetration depths were obtained as a function of pore pressure up to 32,000 psi in both sandstone and limestone rock types at a constant effective stress of 10,000 psi. The results showed that jet penetration continued to decrease even though the effective stress was held constant, from a higher rate of decline between 2,000 and approximately 14,000 psi to a lesser rate of decline between 14,000 and 32,000 psi. Interestingly, the higher unconfined compressive strength (UCS) limestone exhibited slightly deeper penetration than the lower UCS sandstone above a threshold pressure. Visual observations included the location of open zones along the length of the tunnel. The effects of increasing the pore pressure on resulting tunnel geometry were revealed in the high-resolution CT images. The increasingly robust surge, known as dynamic underbalance (DUB), was elevated at each higher pressure, resulting in different perforation tunnel geometries. Further, the limestone generally showed a less disturbed tunnel than the sandstone at the higher pore pressure tests.
This range of pore pressure conditions have never been reached in an API RP 19B Section 2-type test previously. The penetration results should be useful as a predictor of perforator performance whenever higher reservoir pressure well environments are encountered.
Mangala Field Tracer Data Acquisition and Residence Time Distribution Analysis: Results on the Pattern Water Flood and EOR Pilot Area
Authors: Raj Rahul , Verma Sumil , Kumar Pankaj , Kumar Sanjay , Pandey Amitabh 
Published: November 2016

Abstract
The Mangala field in the Rajasthan state of western India was the first major oil discovery in Barmer Basin. The heterogeneous upper Fatehgarh (FM-1 and FM-2 sand) is developed with pattern water flooding. The well fluid are produced through Jet Pump (artificial lift) and processed in a plant (Mangala Processing Terminal, MPT). The separated produced water is mixed with Thumbli aquifer water for injection and as power fluid water for Jet Pump. The injection water is heated above reservoir temperature as to prevent any insitu wax deposition.
To qualify the support of injector for its pattern producers in heterogeneous multi stacked FM-1 sand, conservative tracers were strategically injected in three crestal patterns of FM-1. The paper discusses the results of inter well tracer test conducted in FM-1 sand of Mangala. The paper focuses on the Residence Time Distribution Analysis of Tracer output signal. To meet the actual field condition of tracer reinjection via processed produced water and tracer addition via powerfluid water circulation, some modification in theoretical assumptions of Residence Time Distribution (RTD) analysis are also suggested. The RTD technique is used to estimate the sweep efficiency/ swept pore volume, and to estimate Lorentz coefficient (Lc). The estimated Lc from tracer analysis matches with the Lc being used in the simulation models.
For assessment of EOR potential in Fatehgarh formation, chemical EOR pilot consisting of four injectors and single central producer was conducted in FM-1. Tracers were added in water/polymer/ASP phases of the pilot. The paper compares the sweep efficiency/swept pore volume in three phases of water/polymer/ASP injection with the help of RTD analysis. Better sweep efficiency and more swept volume are observed in polymer phase injection in comparison to the water flooding phase.
The paper also focuses on use of qualitative signature of Tracer output for Reservoir Management and Production Optimization.
Low Resistivity Pay Evaluation, Case Study: Thin Bed Sand-Shale Lamination Reservoirs, Peninsula, Malay Basin
Authors: Amelio Tolioe William , B Mat Ismail M Shah , Angelia Hutajulu Astia , Ragab Gaafar Gamal , Bt Musa Faizah 
Published: November 2016

Abstract
Thin laminations reservoirs of sand and shale, which contains hydrocarbons was determined in some reservoirs at Malay Basin, but not identified as hydrocarbon bearing, or hydrocarbon-in-place are not properly quantified. The net pay and hydrocarbon saturation assessment are a challenge in thin-layered and shaly sand reservoir, with low resistivity and low contrast log response. However, there are several productive reservoirs with similar characters. In thin lamination shaly-sand, fine grained of sand, silt and clay were distributed within the hydrocarbon bearing reservoirs. The character of these reservoirs will be determined as a low net reservoir and reduce the apparent resistivity. Most of the hydrocarbon saturation is difficult to be assessed by conventional log interpretation and leads it as low pay zone or water bearing reservoirs. Meanwhile, the higher cost of exploration and production will determine these as un-commercial reservoirs and the opportunity of this reservoir will often be missed.
The factors that affect the low resistivity low contrast include bed thickness, grain size, mineralogy, structural dip, clay distribution and water salinity or any combination of the above will affect the well logging instrument to measure lower resistivity response than would ordinarily be expected inside a good productive formation. This response of low resistivity-low contrast is due to the low vertical resolution of the conventional logging tools, which can not measure thin-bedded pay zones.
One of the case studies which is presented in this paper, the sequence of sands reservoir from Peninsula, Malay basin has low net reservoir due to high shale contain and low resistivity, almost close to shale resistivity. The well testing and lab analysis prove this interval as oil bearing in the present work we conduct the evaluation of low resistivity-low contrast for thin bed lamination of shaly-sand reservoir to optimize the hydrocarbon saturation quantification. Some approaches were performed to determine shale distribution and saturation hydrocarbon. Thomas-Stieber method was used to determine the shale distribution in the reservoirs and its properties. The horizontal resistivity (Rh) and vertical resistivity (Rv) was acquired on the next closest well to calibrate the resistivity model which using Hagiwara macroscopic anisotropy approach. And Waxman-Smitts method was performed to calculate the final fluid saturation. The hydrocarbon saturation results in thin-bedded reservoirs in the current study was improved this interval was defined as pay zone by perforated it and it produces 600 oil bbl/d and 0.2 mmscf/d. This method can be used for others wells and other reservoirs which have a similarity of geological forces to improve the resource assessment, especially to assess hydrocarbon saturation in pay thin-bedded reservoirs.
Selection and Optimization of Spacer Surfactants for Enhanced Shear-Bond Strength
Authors: Deshpande Abhimanyu , Dumbre Maithili , Palla Venkata Gopala Rao , Rayaprolu Anirudh 
Published: November 2016

AbstractWell-executed cementing is a key parameter for achieving successful zonal isolation to help ensure long-term integrity of the wellbore. Casing centralization, design of wellbore fluids for maintaining density hierarchy, rheological hierarchy and compatibility, and efficient mud displacement are some important factors that affect the efficiency of the cementing operation. For achieving efficient mud removal, and for keeping the drilling mud from direct contact with cement slurry, typically spacer fluids are pumped before cement placement. This can also aid cleaning the casing and formation surface of oil film, thereby helping achieve good bonding with the set cement.Spacers are usually water-based fluids with added surfactants for cleaning the casing and formation surfaces. This surfactant pack is usually optimized using bulk conductivity measurements such that an equi-volume mixture of spacer fluid and mud forms water-external emulsion. However, this might not ensure rheological compatibility between the optimized spacer and the drilling mud at all possible volume ratios. In addition, because the conductivity is a bulk property measurement, it does not give enough information about its wetting characteristics with the casing surface for better bonding.In the present work, a spacer surfactant optimization procedure is evaluated for three different combinations of drilling mud base oil and the surfactant packs. After surfactant pack optimization, the rheological compatibility between the drilling mud and spacer fluid is measured. The rheological measurements showed that not all volume combinations of the optimized spacer and the drilling fluid are compatible. Hence, the spacer surfactant pack is re-optimized for removing these rheological incompatibilities. Further, shear-bond experiments are conducted to measure the efficacy of spacer to clean the casing surface. It is observed that the shear-bond strength varied between the combinations of drilling fluid base oil and the surfactant pack. This study helps in terms of identifying and optimizing a suitable surfactant pack for given drilling fluid base oil for achieving better compatibility and casing cleaning.
Solution to Coning Under Simultaneous Three-Phase Flows for Multiple Vertical Wells
Authors: Phaiboonpalayoi C. , Johns R. T. 
Published: November 2016

Abstract
Coning of unwanted fluids is a significant problem in the reservoir where fluid contacts are close to the producing zone. Coning can lead to a dramatic loss of reservoir energy and result in reserve reductions. The critical production rates to avoid coning can be determined using reservoir simulation. However, history matching are time-consuming and expensive and an accurate result can only be achieved by using small grid blocks near the wellbore.
In this paper, we find a new analytical solution for simultaneous flow of three phases for a single well, and for superposition of multiple wells. The analytical derivation assumes vertical equilibrium, in that any perturbation in the vertical direction is instantaneously equilibrated. Such an assumption gives maximum crossflow and therefore maximum upward and downward coning of the phases. The solution allows for capillary pressure, permeability, and relative permeability variation in the vertical direction.
The new solution is applied to horizontal well modeling using the solution for multiple vertical wells. The new solution also provides an important benchmark for numerical simulation. The physical windows for the phase flow rates from Ansari and Johns (2006) is extended here for this complex case of simultaneous three-phase flow.
An Integrated Approach in Designing an Optimum Single Well Chemical Tracer Test of Hardness Tolerance Surfactant-Polymer, First in Offshore Malaysia
Authors: Zakaria N. , Ghadami N. , Berok S. M. James , Sedaralit M. , Raub M. , Zulkifli N. , Manap A. Abdul 
Published: November 2016

AbstractThe Single Well Chemical Tracer (SWCT) method has proven to be a reliable technique to measure near wellbore residual oil saturation (Sor) and to validate the chemical formulation developed in the laboratory prior to full field Chemical EOR (CEOR). The objective of this work is to establish an inclusive SWCT test program of a new generation Surfactant-Polymer (SP) that can withstand seawater via a holistic approach, making the project first in the world for offshore application.A robust study was carried out to develop an optimum SWCT pilot to validate the chemical effectiveness in terms of Sor reduction between post waterflood and SP flood in one of the Malaysian offshore fields. This paper demonstrates a seamless integration from multi-disciplinary teams to propose a SWCT concept, commencing from a vigorous R&D program to a comprehensive subsurface and surface evaluations, as part of derisking steps of key risks and uncertainties. The SP formulation has demonstrated encouraging outcome in the laboratory. Hence, the results and lessons learnt are required to be validated in the field.Some critical parameters were properly quantified during the fluid-fluid and fluid- rock evaluations in the laboratory such as surfactant-polymer compatibility, phase behavior, interfacial tension, Sor reduction and adsorption to ensure the chemical formulation readiness. The test was designed to utilize one existing producer with minimal workover for cost optimization. A detailed well screening review was performed on the existing wells, with the integrity check surpassed the selection criteria. This consideration is essential to ensure that the selected wells are fit for pilot program, without compromising on pilot objectives. Other selection criteria also included reservoir quality, pay zone thickness, gas interference, and high water cut wells, wells configuration and status. Subsequently, detailed numerical modeling works were performed, including the coreflood modeling for scaling up chemical parameters and radial modeling to reinforce the SWCT test design. Sensitivity analysis were conducted to find the optimum preflush, slug size, and injection rate and flowback period. Similarly, the surface team looked at various concept select options within the constraint imposed by the offshore environment and aging facilities. Due to these challenges, a floating facility, which is an accommodation work barge was selected as the most feasible option to outfit the chemical mixing, injection and back production equipment.This paper elaborates in further details the workflow process from laboratory, well selection and numerical modeling as part of designing an optimum SWCT field trial that meeting all required test objectives, especially in an offshore operation.
Computation of Relative Permeability from In Situ Imaged Fluid Distributions at the Pore Scale
Authors: Zou S. , Hussain F. , Arns J. , Guo Z. , Arns C. H. 
Published: November 2016

Image-based computations of relative permeability require a description of fluid distributions in the pore space. Usually the fluid distributions are computed on the imaged pore space. Recent advances in imaging technologies have made it possible to directly resolve actual fluid distributions at the pore scale, thus capturing a large field of view for arbitrary wetting conditions, which are numerically difficult to reproduce. In previous studies fluid distributions were not imaged under in-situ condition, which may cause oil (non-wetting) phase to snap-off. Consequently computed oil relative permeability is underestimated particularly at low oil saturations. This study extends our previous work by imaging fluid distributions under in-situ conditions as basis for the numerical computations.In this study, we perform steady state flow test on a homogeneous outcrop sandstone (Bentheimer) core. First, the dry core is imaged in our micro-CT facility. Afterwards the core is fully saturated with 0.4 molar NaI solution. The saturated core is then mounted in a specially designed flow cell which allows the flow experiment to be carried with the core mounted on the CT scanner. Afterwards steady state injection of oil and brine is carried out at four different oil/water injection ratios. For each injection ratio, steady state pressure drop is noted and in-situ fluid distributions are imaged under flow conditions. These imaged fluid distributions are used to compute image-based relative permeability. While the measured pressure drops are used to calculate experimental relative permeability.In conclusion, the match between the relative permeability computed from imaged fluid distributions and experimental measurements is excellent. Results demonstrate that imaging in-situ fluid distributions allows us to overcome significant limitations of our previous work: 1) measured and computed oil relative permeability are in close agreement for whole saturation range and 2) laboratory capillary end effects at the core outlet can be imaged which allows us to apply a correction to the laboratory measured data.
Experiment and Modelling of Massive Fracturing Considering Drainage and Imbibition Process in Tight Oil Reservoirs
Authors: Shuai Li , Yunhong Ding , Bo Cai , Yongjun Lu 
Published: November 2016

AbstractSpontaneous imbibition is an important process to increase oil recovery in fractured carbonate reservoirs. Due to the nano-scale pores and throats distributed in tight oil reservoirs, capillary pressure became much larger, which may result in a much stronger imbibition.An experimental and modeling was adopted to simulate drainage and imbibition process in hydraulic fractured tight oil reservoir. Firstly, 400 mm×100 mm×30 mm core samples were used to simulate forced displacement and spontaneous imbibition of fracture surface at in-situ conditions of pressure. Secondly, 1D model for counter-current imbibition was solved on some assumption of relative permeability and capillary pressure, numerical results obtained by COMSOL as verification.Results have indicated that recovered oil was 0.19 mL in spontaneous imbibition condition while was 0.62mL in combined condition of forced displacement and spontaneous imbibition. Saturation front contacts the sealed end-face much faster with forced pressure condition. According to this phenomenon, it can be inferred that the main direction of aqueous phase in the shut-in period is form large pores to smaller pores. Aqueous phase was pushed into the large pores by forced pressure, and imbibed into smaller pores in the function of capillary pressure. 1D model of 2 phases counter-current imbibition solved with Galerkin method is in correspondence with numerical result at the same assumption. With the increase of dimensionless distance (X) and dimensionless time (T), water saturation profiles were drew and were contrasted with CT scanning.Forced displacement and spontaneous imbibition simultaneously occurs during fracturing and shut-in duration. Study of this can provide a reference for soaking management and a good way to increase well productivity.
Growth Fault in Longmaxi Shale and its Importance for Sedimentary Distribution and in Situ Stress Direction-A Typical Case from southeastern Sichuan Basin, China
Authors: Wang ZhenXing , Chen JieYing , Pan Feng , Wang DaLi 
Published: November 2016

Abstract
The complex fault system formed due to periods of tectonic movements always raised the risk of shale gas E&P activity. Faults with large displacement can be easily recognized on seismic profile, but mini faults are hard to find even though they have non-ignorable impact on well palnning. This paper ultilzed the borehole image data to distinguish the mini fault and analysised how the mini fault can influence the sedimentary and in situ stress disturibution.
Stratigraphic dip patterns from images, integrated with core data and conventional logs, can ascertain the fault position in the wellbore and help define the fault property, such as fault azimuth, dip amplitude, fault displacement, and the fault-related geological deformation. The dip patterns showed abrupt change around the fault breakpoint at which depth the image structure was disordered, the cores broke into pieces, and the marker values on the conventional logs were missing compared with adjacent wells. Sedimentary features observed on the images also revealed different structures between hanging wall and foot wall of the fault in the wellbore. All of above proved the existence of the normal fault.
Cross section images were used to evaluate this fault and its associated depositional architecture. In the target shale interval, the wells on the cross section show strong comparability of thickness and stratigraphic dip patterns which are mainly green patterns. However, the dip patterns in the same interval demonstrated green-red-green patterns in the well where the fault was discovered. Morover, a set of sandy turbidities overlied on the target shale can be found in all of the wells on the section. It has thinner trend towards the south, but unexpectedly became thicker in the well with the fault. A great amount of syngenetic deformational structures were also recognized on the image of the hanging wall of the fault, while the foot wall is dominated by parallel bedding and low angle cross bedding. Those phenomenon indicated that the fault is a typical normal growth fault. Furthermore, the in situ stress direction reflected by the wellbore failure demonstrated that the in situ stress changed its direction around the fault plane. It is concluded that the fault controlled the sedimentary distribution in the depositional period and influenced the in situ stress direction during tectonic movements.
The analysis of the stratigraphic dip patterns from the images complemented the accuracy of seismic data in the geological structure interpretation. The understanding of the growth fault have realistic meaning in both studying the sedimentary facies distribution and predicting in situ stress direction.