bluuebunny/crossref_metadata_2025 huggingface dataset:
A Laboratory Study of In-Depth Gel Treatment To Improve Oil Recovery
Authors: Wang Jinxun , Alshehri Ammar J. , AlSofi Abdulkarim M. , AlBoqmi Abdullah M.
Published: June 2017

The extreme heterogeneity of carbonate in the form of fracture corridors and super-permeability thief zones challenges the efficient sweep of oil in both secondary and tertiary recovery operations. In such reservoirs, conformance control is crucial to ensure injected water and any enhanced oil recovery (EOR) chemicals optimally contact the remaining oil with minimal throughput. Gel-based conformance control has been successfully applied on both sandstone and carbonate reservoirs. In-depth conformance control in high temperature reservoirs is still a challenge, due to severe gel syneresis and the associated significant reduction in gelation time.

In this work, a laboratory study was conducted on a polymer/chromium gel system for a high-temperature carbonate reservoir to evaluate the gelant formulation potential for diversion and recovery improvement. We perform four oil displacement experiments on carbonate core samples to demonstrate oil recovery improvement by gel treatment. In these tests, the gel solution was injected into specially prepared heterogeneous carbonate composite core samples, in which different configurations of high permeability channels were created. Gel treatment was conducted after waterflooding and was followed by chase waterflooding while monitoring oil production. Oil recovery improvement by gel treatment was 18% of original oil in core (OOIC) in the composite core with high permeability channels extending midway through the composite while the improvement was 38% OOIC in the composite core with channels extending all the way through the composite. This indicates that the high permeability channels were effectively blocked and bypassed oil was successfully mobilized after gel treatment.

This laboratory study provides more insight into the mechanisms of oil-recovery improvement by gel treatment. Moreover, it clearly demonstrates the oil-recovery potential of in-depth gel systems in heterogeneous reservoir applications at high temperatures.
New Advancements in Mitigating Sand Production in Unconsolidated Formations
Authors: Kalgaonkar Rajendra , Chang Frank , Ballan Abdel N , Abadi Abdullah , Tan Xiaoyu
Published: June 2017

Sanding in oil production and water injection wells has been a severe problem in a sandstone formation. Many technical solutions have been evaluated by Saudi Aramco. These solutions encompass mechanical sand exclusion methods such as screen, gravel packing, and frac and pack. Various production and completion practices such as controlling the production rate and following specific well completion guidelines to minimize sand production have failed to provide satisfactory returns.

Several limitations such as screen plugging and costs associated with deploying expandable screens make the current mechanical sand control practices more expensive. Chemical sand consolidation could present the most cost-effective remediation and prevention opportunity. Additionally, this would also allow the wellbore to be free of tools, screens and pack sands.

With the cost benefit and technical challenges in mind, a new chemical system was developed to effectively consolidate loose sand, which has caused injectivity and productivity decline and costly clean out operations. The newly develop chemical system is based on resin backbone with a curing agent to harden under reservoir temperature. A permeability enhancing additive is incorporated in the system to achieve excellent and controllable regained permeability of the consolidated sand pack.

This paper presents the new advancements in preventing wellbore sand production. The newly developed sand consolidation chemical was studied for their ability to consolidate loose sand and at the same time maintain good permeability. The new sand consolidation chemical system showed several key advantages over the current commercial products, including its easy mixing procedure and superior performance in consolidation strength and regained permeability. It was shown that the permeability enhancer incorporated in the new sand consolidation product is the key to maintain superior regained permeability. In addition, it was shown that the new product provides a controllable curing time up to several days, thereby avoiding any premature setting of the resin in the wellbore. Furthermore, the new system is also compatible with acids to eliminate any post-job production issues if the formation is acidized in the future.
Success of Achieving Zero Discharge to Pit by Injecting in High Karst Shuaiba Formation in Umm Gudair Field
Authors: Al-Azmi Ali Abdullah , Tiwari Brajesh Kumar
Published: June 2017

Umm Gudair is the second largest field of West Kuwait Directorate. The majority of production in comes from Oolite reservoir. The production from the field began in early 1950's and as maturing of this field, the associated water production has significantly increased which has resulted in an environmental hazard in handling and disposing of the large volume of produced water.

West Kuwait Asset has two major producing fields which are Umm Gudair and Minagish. Water management in West Kuwait was designed to integrate all effluent water from gathering centers in West Kuwait through the Effluent Water Transfer System and the Minagish Water Injection Plant (MNWIP). All effluent water is transferred from the gathering centers through the Effluent Water Transfer System to the MNWIP for re-injection into the Minagish Oolite (MO) reservoir in the Minagish field (MN) for pressure maintenance. The re-injection of effluent water produced from WK fields into the Minagish Oolite reservoir of MN field has significant impact. Also, Mega disposal wells completed in the karsted Shuaiba formation as a back-up plan in case of any planned or unplanned shutdown of the MNWIP.

The success of many oilfields depends upon efficient disposal of produced water. A number of standard approaches were taken to obtain injection rates up to +20,000 BWPD per well on gravity feed. A multi-disciplinary team was formed to review the practical and theoretical aspects of formation damage and water quality. Successful injection at rates exceeding 60,000 BWPD per well were subsequently achieved by a proper completion design for the mega disposal wells and improving water quality.

This paper deals with the learning curve and dead ends that led to the successful subsurface disposal capacity of over 400,000 BWPD in High Karst Shuaiba Formation and achieving zero discharge to the pit. A holistic approach for monitoring and surveillance plan for wells with periodic review of current condition is adopted keeping cost effectiveness as an important parameter.
Jumping Mass Spectrometer
Authors: Rowe Mathew , Splapikas Tony
Published: June 2017

Current surface gas detection technologies are flawed in that they are limited in speed or can only detect certain gas types. Current gas detector technology does not provide a complete view of reservoir conditions without additional and costly inferred measurements from logging while drilling (LWD) or wireline tools. To overcome these limitations, a new instrument and methodology have been adapted from the chemical process industry and developed for drilling applications.

The initial goal was to develop a gas detection system capable of quantitatively analyzing more than 20 chemical species in less than 15 seconds. Several gas analyzers were reviewed for ruggedness, speed, accuracy, and chemical species detected. The system had to be capable of withstanding shipment to the rigsite and rigsite conditions. In addition, the system needed to be operable remotely to reduce personnel at the site. A gas chromatograph flame ionization detector (GC-FID) was used as the benchmark for accuracy and response.

A quadrupole mass spectrometer that would jump from mass peak to mass peak was selected. This spectrometer is characterized by an accuracy rate within 0.1%, a faster response time than a GC-FID, and the ability to analyze 32 chemical species in less than 10 seconds with drift less than 0.1%. The system was the best match to meet the initial goal. Developing a quantitative mass spectrometer proved to be a greater challenge. This objective was achieved by determining the chemical species fragmentation patterns and sensitivities at the base before deploying the system to the rigsite, where only a verification gas blend was necessary. The system can replace slower, qualitative mass spectrometers at the rigsite at a reduced cost with 10 times the data density.

The initial goal of developing a system capable of analyzing more than 20 chemical species in less than 15 seconds was achieved. Additionally, adapting instrumentation and methodology from the chemical process industry to drilling applications led to the development of a fully quantitative mass spectrometer at the rigsite with cycle times of less than 10 seconds for 32 chemical species.
Development Strategy Optimization for Different Kinds of Tight Oil Reservoirs
Authors: Hui Peng , Qiquan Ran , Yong Li , Yongjun Wang
Published: June 2017

Tight oil has large amount of resources and enormous potential in development. Application of volume fracturing on horizontal wells has a significant impact on tight oil development. But with continuing low oil price, development strategies should be more effective in order to maintain the economic development of tight oil reservoirs. This paper presents a case study of development strategy optimization for different kinds of tight oil reservoirs in China.

This paper focuses on MZ tight oil field in China. And reservoir properties and fractures of DAZ reservoir is better developed than that of LGS reservoir of MZ oil field. Based on geological understanding and dynamic characterization on the two formations, two representative sectors of each reservoir are selected. And corresponding geological and numerical simulation sector models are established. Finally, development strategies are optimized through reservoir simulation.

The optimized parameters include the length of horizontal section, well spacing, fracture segments spacing, fracture half-length, etc. Sensitivity analysis of all parameters are conducted based on the established simulation models. For DAZ reservoir, the optimized development strategies are: 2000m horizontal well length, 700m well spacing with 300m fracture half-length and 20 fracturing stages. While for LGS reservoir, the optimized development strategies are: 2500m horizontal well length, 800m well spacing with 350m fracture half-length and 22 fracturing stages. Although longer horizontal well and more fracturing stages for LGS reservoir, the predicted average well cumulative oil production within 10 years is still lower than that of DAZ reservoir because of the poorer reservoir quality of LGS reservoir.

This paper offers a case study on development strategy optimization for different kinds of tight oil reservoirs. The results have been applied to the two tight oil reservoirs in MZ tight oil field in China with successful results. It also provides a methodology and reference case for engineers and geologists to develop other similar fields.
Performance Analysis and Flow Regime Identification of Fractured Horizontal Wells in Tight Oil Reservoirs
Authors: Hui Peng , Qiquan Ran , Yong Li , Min Tong
Published: June 2017

Fractured horizontal wells are widely used to produce tight oil. But different fracture patterns could be generated in different reservoirs, which results in different well performances. How to identify the flow regimes and their impacts on performance is still challenging. This paper provides a method for flow regime identification of horizontal wells with different hydraulic fracture patterns in tight reservoirs.

First, four different fracture patterns of hydraulically fractured horizontal wells in different types of tight oil reservoirs are classified, according to the fracture network identified from micro-seismic observation and laboratory experiments. Then, corresponding well performances are simulated based on various conceptual reservoir simulation models. The simulation results are further used for rate transient analysis. Finally, flow regimes and corresponding production periods of each pattern are identified and classified, and well performances are also analyzed.

Flow regimes of different fracture patterns are identified based on rate transient analysis with input of reservoir simulation results. Different patterns have different flow regimes. For instance, there are linear flow, radial flow and boundary dominated flow in Pattern A, while bilinear flow, linear flow, radial flow and boundary dominated flow are prevail in Pattern C. The corresponding production phase of each flow regime is also classified. It can be seen that different scales of pores and fractures have different impacts on different patterns and production phases. In pattern A and Pattern D, large fractures determines the initial production rate and performance of linear flow, and more oil is produced in linear flow stage than in radial and boundary dominated flow periods. While in Pattern B and Pattern C, micro-nano fractures and pores are much more developed, which have more cumulative production and better performances during radial flow and boundary dominated flow.

The results are applied to the tight oil reservoirs in Junggar and Erdos Basin in China. Analysis of all fractured horizontal wells indicates that most are pattern A and Pattern B, and linear flow occurs in the early production period in all the patterns. If hydraulic fractures are long enough, bilinear flow could happen. Well performances are correctly predicted based on the well flow regime identification.
Reservoir Simulation History Matching and Waterflooding Performance Forecast for a Large Sandstone Reservoir in Middle East
Authors: Yong Li , Baozhu Li , Benbiao Song , Weimin Zhang , Qi Zhang , Xiong Lihui
Published: June 2017

For the same reservoir geological model, different simulation models could be obtained through history match calibration by different engineers. In other words, there are certain uncertainties within the calibrated simulation models. So how to reduce the uncertainty during history matching is still a problem. This paper presents how to quantify the waterflooding uncertainty and reasonably forecast waterflooding performance through reservoir simulation for a large multi-layered sandstone reservoir in Middle East.

Based on the results of detailed geological characterization, dynamic description and parameter uncertainty analysis, three fine geological models are built, which stand for upside model, expected model and downside model. Then parameter sensitivity on waterflooding performance is conducted based on sector model simulation, and waterflooding development strategies are also optimized. The results are firstly applied for the three full field model calibration by reservoir history matching. After that the calibration models are used for waterflooding performance forecast and the performance uncertainty are also quantified.

Take a large multi-layered sandstone reservoir in Middle East as an example. The MU reservoir is still under primary depletion with only 5% recovery currently, and waterflooding is urgent. Firstly, sector models are used for parameter sensitivity analysis and development strategy optimization. Then based on parameter sensitivity analysis results, the three full-field model are all calibrated with good history match. And different model calibration need different parameter adjustment, such as downside model has stronger aquifer support than that of upside model and expected model because of the poorer connectivity. So different models show different characteristics, such as most of west-south flank of MU reservoir are flooded for Downside model, while only some local area and some zones are water flooded for Expected and Upside model. Then waterflooding performance of different development plans are forecasted and compared based on the optimum development strategies and calibrated models. Furthermore, the performance uncertainty are quantified based on the three models.

This paper offers a methodology and a case study of reservoir simulation history matching in order to reduce uncertainty and better waterflooding performance forecast for a large sandstone reservoir in Middle East. Comparison of the three models can help to better understand the reservoir. And the results are valuable for the following development options decision making. It also provides a reference for performance forecast and uncertainty analysis of similar reservoirs.
Bit Wear Control and Optimization in Autonomous Rotary Steerable Drilling
Authors: Kamel M. A. , Elkatatny S. , Mysorewala M. , Al-Majed A. A. , Elshafei M.
Published: June 2017

Directional Steering System (DSS) has been established for well drilling in the oilfield in order to accomplish high reservoir productivity and to improve accessibility of oil reservoirs in complex locations. Rotary Steerable System (RSS) is the current state of the art in directional drilling. In this work, we address the problem of real time control of RSS with unknown formation friction and rock strength. The work presents an online control scheme for real time optimization of drilling parameters to (1) maximize rate of penetration, (2) minimize the deviation from the planned well bore trajectory, and (3) assess the degree of bit wear. Nonlinear model for the drilling operation was developed using energy balance equation, where rock specific energy is used to calculate the minimum power required for a given rate of penetration. The bit wear is mathematically represented using Bourgoyne model. Detailed mathematical formulation and computer simulation were used for evaluation of the performance of the proposed technique, based on real well data. The obtained results showed excellent ability to accommodate the changes in the formation properties. In addition, the rate of bit wear has been optimized.
Use of 4D Seismic To Boost The Profitability Of Infill Drilling In An Offshore Sandstone Oil Field
Authors: DARAMOLA Babalola
Published: June 2017

This paper presents how 4D seismic was used to boost the profitability of an infill production well (XA) in Field X located offshore Nigeria. Field X has an anticline dome structure with sizeable faults and turbidite sandstone reservoirs. It had under-saturated oil at initial conditions, and has been developed with 4 subsea production wells and 2 subsea water injection wells tied back to a leased FPSO vessel.

An Eclipse simulation history match model was constructed in 2012 to support the infill production well proposals XA and XB. The simulation model estimated the oil recovery from infill well XA as 1.57 MMSTB, which was deemed uneconomic. A review of the 2012 simulation model used for the recovery assessment suggested that the XA area was swept by a nearby water injection well (W1). This did not agree with the 4D seismic data. The simulation model water cut in a nearby production well (P1) was also higher than the actual water cut.

It was concluded that the simulation model did not represent actual reservoir performance. The simulation model was optimised by improving the XA infill well path penetration in the target reservoir formation. The connectivity between the W1 water injection well and the production wells was also evaluated. A seismic section between W1 and P1 showed a potential flow baffle between the wells. This baffle was added to the simulation model to delay the water between W1 and P1. Production data suggested that W1 was most likely connected to another production well (P3) via a high conductivity channel. The channel was added to the simulation model to divert most of the water from W1 to P3. These actions improved the P1 water cut and 4D seismic water saturation difference history matches, increased the XA infill well oil recovery by over 50%, and made the well economic.

This paper presents a standard method of how 4D seismic data was used to support infill well planning, and can also be used to justify 4D seismic data acquisition. It is recommended that reservoir simulation models are history matched with 4D seismic and other geologic and production data prior to using the models for prediction and well placement. In this case study, 4D seismic data was used to improve the simulation history match and boost infill well economics. 4D seismic can also be used to locate sealing faults, evaluate fault seal breakdown, find infill well locations, and improve oil recovery.
Introducing a Universal System Design and Workflow for Efficiently Capturing and Managing Geological Modelling Data Assets
Authors: Ibrahim Mohamad A. , Bin Mahfoodh Abdulelah , Hawi Maan
Published: June 2017

Recently, the oil and gas industry witnessed an increased demand for executing complex and large-scale drilling activities that require accurate understanding of subsurface conditions and precise geological observations. To accomplish this, three-dimensional geological modelling is commonly used to accurately define sub-structural and physical properties in the areas of interest. Moreover, geological models are used as input to reservoir simulators to predict underground fluid behavior and ultimately to identify the most efficient, sustainable and economic hydrocarbon recovery scenarios. A geological model is a computerized 3D representation of the earth crust and subsurface based on a set of geological and geophysical properties and is generated using various computer applications.

Over the past years several geo-scientific software technologies were developed to address this increased demand of geological modelling. However, existing commercial geological modelling applications are unable to provide a systematic approach to manage and control various workflows and data assets generated during and after the modeling process. Occasionally, professionals encounter loss of geological modeling projects or the input data used to generate them or even their metadata because there exists no solution to manage and archive this important data asset. Furthermore, practical surveys show that there is also a need for a full dynamic data integration solution to optimize and streamline different processes and activities related to geological models and conducted by geologists, geophysicists, and reservoir engineers.

This case study presents Saudi Aramco's innovative approach of in-house designing and implementing a system to capture and manage geological modelling data assets regardless of the vendor application used for generating them. This system captures geological models projects and their input data with enforcement of a proper data classification and provides archival, tracking, and retrieval workflows across different stages. Additionally, the system provides an interface enabling professionals to search captured geomodels by their respective metadata such as date, well name, reservoir, model type, etc. This new data management system plays a significant role in streamlining geological models data integration while improving data quality and productivity of geoscientists and engineers by providing efficient access to data assets.
Identification and Characterization of Thermally Induced Fractures Using Modern Analytical Techniques
Authors: Almarri Misfer , Prakasa Bona , Muradov Khafiz , Davies David
Published: June 2017

Thermally Induced Fractures (TIFs) are common in waterflooded fields where the injection of (relatively) cold water leads to a cooling front that reduces the formation's in-situ stresses. TIF initiation and growth can thus occur when the previously measured, fracture propagation pressure is not exceeded. The presence of TIFs severely distorts the flood front, decreasing sweep efficiency. This paper applies several published, waterflood analysis methods to TIF characterization in synthetic and real case studies.

These methods include well injection history data using modified Hall analysis, injectivity index and pressure vs. rate analysis, etc. to identify the onset of TIF, its propagation and its properties. The Capacitance Resistance Model (CRM) is chosen to quantify the change in inter-well communication due to TIF, the likely TIF direction and its impact on the flood front. Application of these models is illustrated and verified using reservoir geomechanical/fluid flow simulations. In addition, a field case study is used to demonstrate the value of integrating analytical and semianalytical models when developing an improved understanding of TIF evolution in waterflood operations

Results from synthetic examples using the proposed analytical models confirm that the models correctly identify the onset, monitor the evolution of TIF, and provided valuable insights into the overall well injection performance. The CRM model quantified the connectivity between well pairs, identified TIF initiation and its subsequent impact on well connectivity and flood efficiency. The same techniques are used to analyse data from a real-field case history. TIF initiation and propagation events were clearly identified, even when their existence was much less certain with the other techniques. A correlation between the injection water temperature and the TIF growth dynamics was observed while the well production data and FMI images supported our analysis.

The novelty of the presented approach is in efficiently integrating the recent, analytical and semianalytical models to identify onset, propagation, characteristics, and impact of TIF from the generally available, well injection production history data. The practical workflow employed here will help engineers detect and monitor TIFs; as well as evaluate the metrics describing waterflood performance, namely flood efficiency, inter-well communication and pressure maintenance.
The Use of Artificial Neural Networks to Quantify the Effect of Formation Damage on Well Production Response
Authors: BuKhamseen Nader Y. , Ertekin Turgay
Published: June 2017

This paper presents a workflow that evaluates whether the production rate decline or abnormal pressure behavior is attributed to formation damage. The workflow uses artificial neural networks (ANN) as the engine behind the evaluation process. All the training and validation data comes from a reservoir simulator. The required parameters that are used for building the neural networks are the completion factor (RF) and skin. These parameters are then used to match the production and pressure profiles of the subject well.

Formation damage refers to the reduction of the effective permeability near the wellbore. There are several causes of formation damage including but not limited to the completion and workover fluid, fines movement, and scale deposition. In this paper, the effect of plugged perforation sets and skin are examined. If the reservoir simulation model has a suitable history match, the model response should not considerably deviate from the real well response. If that deviation occurs, the developed ANN is introduced to check if that deviation is a result of formation damage. The reservoir simulator is used to generate several data sets with variable completion factors (RF) and skin parameters to be used for training and testing the ANN. The RF and skin can vary through time to reflect the actual changes in production response. The ANN then outputs the RF and skin factor based on the observed pressure and production profiles. The recommended output of the ANN is eventually validated with the reservoir simulator.

This workflow has been tested on a synthetic, heterogeneous reservoir model. Results show good prediction capabilities for the developed ANN in terms of producing formation damage parameters that correspond the simulated data. The workflow also suggests which parameter (the RF factor or skin) should be updated in the reservoir simulation model to reflect the observed production response.

The results indicate that the data for the subject wells in the reservoir simulation model can be updated in a fast and efficient way using ANN. The ability to vary the number of layers, number of neurons, learning rate, and training algorithm makes the ANN a suitable tool for tackling problems where the relationship between parameters is difficult to comprehend.
Probabilistic Performance Forecasting in History Matching of Low Permeability Reservoirs
Authors: Zhang Xuejiao , Xue Yongchao , Ding Guanyang
Published: June 2017

Since conventional history matching aimed at fractured horizontal wells in low permeability oil reservoirs is affected by a number of factors, such as permeability, fracture half-length, conductivity and so on, there often exists ambiguity in production matching. That is to say, when showing the same curves and results, we cannot make a definite decision to judge which parameter displays the matching results. In this paper, Markov Chain Monte Carlo (MCMC) and AM algorithm are presented to improve history matching and then to obtain more accurate probabilistic production forecasting using actual decline production data. First, the AM algorithm, having an advantage of updating parameters simultaneously and constituting a proposal distribution at each new iteration according to the covariance matrix of the previous iterations over the Metropolis-Hasting (MH) algorithm, is employed to gather field production decline data. Furthermore, MCMC method is utilized to develop a Markov Chain, a stochastic process with a series of various parameters and later value usually only related with the most-recent value. Finally, based on this, the history matching is improved and further probabilistic production prediction P10, P50 and P90 are achieved.

The results indicate that compared with MH algorithm, the AM algorithm can get a greater acceptance ratio. The Markov Chain for production decline data parameters shows a satisfying mixing. The probabilistic cumulative oil production of P10, P50, and P90 is established for target oilfield in this paper. The curves of production rate versus time and cumulative oil production versus time show that the well-established Markov Chain can successfully match the production decline data and then perfectly predict probabilistic production. The novel point in this paper is that a much more effective AM algorithm substituting for the MH algorithm is adopted to form the Markov Chain to improve history matching. The results manifest that MCMC method has the ability to enlarge the reliability of production forecasts, which has a significant influence on reservoir understanding and management.
Dynamic Characterization of Different Reservoir Types for a Fractured-Caved Carbonate Reservoir
Authors: Yong Li , Qi Wang , Baozhu Li , Zhiliang Liu
Published: June 2017

Understanding reservoir types or reservoir patterns is critical for a successful development strategy decision in carbonate reservoirs. For the fractured-caved carbonate reservoirs in china, reservoir types are especially important because different reservoir types may apply different development strategies. This paper propose a systematic method of dynamic characterization on a carbonate reservoir in China.

The proposed systematic dynamic characterization method mainly includes production data analysis and well test analysis, which combined with geological understanding. It is applied to the Ordovician fractured-caved carbonate reservoir in China, which has different reservoir types developed. Different reservoir types are classified and identified, and three of them are illustrated in detail.

Based on the geological features of K fractured-caved carbonate reservoir in China, forward modeling method is firstly used for identification type curve generation of different reservoir types. Different numerical reservoir models are built, and the type curve of well test and rate transient analysis are generated. And the results are used for the actual reservoir type identification. Then combined with geological understanding, reservoir properties and reservoir types are evaluated based the dynamic methods, which include well test analysis and rate transient analysis method. Three reservoir types, which include volumetric caved reservoir, fractured reservoir, fractured-vuggy reservoir, are characterized based on the proposed methods and presented in detail. More than one hundred of reservoirs are evaluated. It is found that OOIP of most reservoirs are lower than 200 thousand cubic meters, and skin factor of most wells are lower than zero.

The understanding of reservoir types and dynamic characterization results are much valuable for the next development options decision, which are applied to the K fractured-caved carbonate reservoir with successful results.
Applications of High-Resolution LWD Resistivity Image Logs for Carbonate Reservoir Characterization
Authors: Wang W. H. , Thagafy M. M.
Published: June 2017

Logging while drilling (LWD) resistivity imaging was typically deployed to provide real-time LWD images to identify critical geological information, e.g., bedding dip changes, lithology changes and large faults to allow optimum geosteering. During the past decade, there has been a progressive increase in the along hole resolution of LWD images, and today's highest resolution tools achieve nominal along hole resolutions of approximately 0.5-in. with full 360° azimuthal borehole wall coverage.

The focus of this study is the high-resolution LWD resistivity images recorded downhole as the memory mode data and their direct comparison with images from conventional open hole ("wireline") resistivity images, to illustrate the similarities and differences between images from the two technologies for fracture characterization and vuggy porosity partitioning in carbonate reservoirs.

Fracture types, distribution and their orientation can be determined from LWD image logs. Proportion of vuggy porosity can be estimated from LWD images by applying porosity-partitioning technique. This study shows that the images generated from the new generation of high-resolution LWD resistivity imagers have sufficient effective along hole resolution to offer an alternate to the conventional open hole images for carbonate reservoir characterization.
ROP Enhancement and Drilling Time Optimization for Long Horizontal Sections in Tight Gas Formations Utilizing MPD Systems – A Case History
Authors: Han Kyungnam , Alexeyenko Alexey , Chavarria Marcos , Markabi Mazen
Published: June 2017

An exploration well was commissioned to evaluate a potential tight gas reservoir by drilling a combined curve and horizontal section while facing a narrow mud weight window (NMWW). Positioned below an anomalous formation, a high probability of influx, losses and stuck pipe scenarios prevailed, coupled with a very low ROP scenario. Also, being a rather long combined curve and lateral section, there was a high risk of caving after drilling, which could disrupt running the liner.

To land the well on target without having any undesirable effects, it was critical to maintaining correct pressure profiles not only during drilling but also during tripping and setting/cementing the liner. A thorough hydraulics analysis and carefully executed MPD design were used to maintain a constant bottom-hole pressure during drilling, connections, and tripping. The MPD system was fully capable of recognizing drilling parameters in real time and adjust surface pressure accordingly. This allowed the 5-7/8 in. section to be drilled using the lowest possible mud weight while attaining the necessary overbalance.

The lateral section was successfully completed to improve the stipulated timeline. This was attributable to ROP improvement by 29% and also to 164% footage drilling enhancement per bit run, which allowed the drilling team to finish the 5 7/8 in. hole section in record time compared to the offset wells. By using correct mud formulations and accurate wellbore pressure mapping, there was no loss while drilling the section; and the Early Kick Detection module was successfully deployed to accurately monitor influxes. Whenever a discrepancy was observed between the flow in/out, the MPD system was fine-tuned to adjust the pressure profile to match the two flows. Following drilling, the wash-down LWD was utilized with MPD and low mud weight. The liner was run and set, while the hole was filled with a low weight mud, using the MPD system. There were no tight spots or caving observed in the whole run and the liner was able to reach the bottom with no issues. A detailed paper would discuss the in-depth technical analysis of this case history.
A Novel Two-Stage Treatment to Remove Scales from Oil Producing Wells in a Sandstone Reservoir
Authors: Alfakher Basil M. , Al-Taq Ali A. , Alrustum Abdullah A. , Altawfiq Ali M. , AlHashim Hassan W.
Published: June 2017

Several oil producer wells in a sandstone reservoir have experienced productivity decline due to obstruction material. Bailer samples were collected at different depths to identify the nature of the obstruction material and recommend an optimized remedial treatment to restore productivity of damaged wells. The samples were found to be heterogeneous and contained different types of scales including calcite and iron containing compounds. Various forms of iron sulfides, iron hydroxides were present in the collected samples at different concentrations. Sand, elemental sulfur and trace amounts of iron oxides were also present in some of the samples.

Mechanisms of scales formation were investigated in this study to recommend prevention measures. As an example, greigite (Fe3S4), present as one of the major scales (49 wt. %) in one of the samples, may form due to the reaction of iron sulfide (FeS) with excess sulfur, both detected in the sample. Formation of iron sulfide was attributed to SRB's which dictates the need to have effective biocide treatments.

Solubility tests of collected scales in different dissolver systems were examined as a function of temperature and soaking time. Among other examined dissolver systems, (HCl) acid was found to be the most effective. Effects of acid additives on the solubility of scales were examined in order to optimize the acid recipe. The formation of interest is sandstone containing up to 2 wt. % authigenic clays. The use of HCl acid may induce fines migration and sanding problems. Based on lab results, a novel two-stage remedial treatment is recommended to restore productivity of damaged wells. The first stage involves treating the wellbore with HCl acid including the required additives to remove the scaling material from the wellbore area. The second stage includes incorporating organic acid to stimulate the formation matrix.

This paper presents a study detailing the design of a novel two-stage treatment able to remove scales and overcome some of the anticipated challenges in stimulation of sandstone formations. The paper also addresses results of extensive lab work conducted to optimize the treatment recipes.
CO2-Based Technologies in Unconventional Resources: Impact of Rock Mineralogy on Adsorption
Authors: Al Ismail Maytham , Zoback Mark
Published: June 2017

Low pressure sorption analysis and CO2 adsorption measurements were carried out on shale samples from the Utica and Permian basins. To determine the impact of rock mineralogy on the adsorbed volume of CO2, the mineral compositon of the studied samples varied. For example, the clay content of the studied samples ranged between 5% and 53%. The low pressure sorption analysis was conducted to estimate the pore-size distribution for the shale samples. Then, CO2 adsorption was measured using the volumetric method applied on an in-house experimental apparatus to generate the CO2 adsorption isotherms. The adsorption measurements were performed on crushed samples to speed up the equilibrium process. During the adsorption measurements, the temperature of the system was maintained at 40°C.

The adsorption measurements revealed that the adsorbed volume was controlled mainly by the clay content. A ~30 wt% increase in clay content resulted in an increase of the adsorbed volume by an order of magnitude. The adsorbed volume of CO2 ranged between 27 scf/ton and 152 scf/ton for the Utica shale samples and between 60 scf/ton and 640 scf/ton for the Permian samples. Based on pore-size distribution analysis, clay minerals (i.e. illite) provided the surface area for adsorption. SEM images using energy-dispersive X-rate spectroscopy (EDS) obtained for a clay-rich shale sample confirmed that the platy structure of the illite provided the surface area for increased adsorption capacity.

CO2-based technologies are emerging in the oil and gas industry for CO2 storage, stimulation and enhanced recovery. This study has shown that clay content significantly impacts how CO2 interact with the rock. Therefore, to optimally design the CO2-based technologies, rock mineralogy shouldn't be ignored.
Vegetative Composition, Arbuscular Mycorrhizal Fungi Root Colonization, and Biological Nitrogen Fixation Distinguish Organic and Conventional Perennial Forage Systems
Authors: Schneider Kimberley D. , Lynch Derek H. , Bünemann Else K. , Voroney R. Paul
Published: June 2017

Core Ideas

Conventional and organic forage fields did not differ in total forage yield.

Legume content was more than two times greater under organic management.

Total forage biological nitrogen fixation was greater under organic management.

Arbuscular mycorrhizal fungi root colonization was greater under organic management.

Arbuscular mycorrhizal fungi root colonization was inversely related to soil test P concentrations.

Low concentrations of Olsen soil test phosphorus (STP) on organic dairy farms in Canada have been reported, however, the resulting impact on crop productivity is unclear. This study evaluated mixed forage (alfalfa [Medicago sativa L.]/timothy [Phleum pratense L.]) productivity, nutrient uptake, and related soil biological and biochemical properties on organic and conventional dairy farms in Ontario, Canada. Despite a lower STP concentration, mean organic forage yield (8.0 Mg DM ha−1) did not significantly differ from conventional (9.5 Mg DM ha−1). The proportion of N derived from biological nitrogen fixation (BNF) in alfalfa did not differ by management system, however the total forage BNF‐N was greater in the organic fields due to a twofold increase in legume proportions. Alfalfa tissue P concentrations, above the suggested critical value of 2.0 g kg−1 in all systems, were positively correlated with STP (r = 0.82, P = < 0.0001) and significantly greater in conventional (3.3 g kg−1) than organic (2.4 g kg−1). Mean arbuscular mycorrhizal fungi (AMF) root colonization of alfalfa was greater in organic systems (37 vs. 23%) and was negatively correlated with STP (P = 0.0006). Management systems did not differ in soil alkaline and acid phosphatase activity, or phytase‐labile P. It was concluded that legume‐based forages can produce acceptable yields at low STP concentrations (<10 mg kg−1) and supports the importance of legumes, legume BNF, and biological processes linked to soil P cycling in maintaining productivity in organic dairy farming systems.
Evaluation of Environmentally Smart Nitrogen in Winter Wheat in North Carolina
Authors: Rajkovich Shelby R. , Osmond Deanna L. , Weisz Randy , Crozier Carl
Published: June 2017

Core Ideas

Environmentally Smart Nitrogen (ESN) and ESN mixtures with ammonium sulfate did not increase grain yield over urea–ammonium nitrate.

Effects of ESN timing varied due to year and physiographic region.

Environmentally Smart Nitrogen does not appear to provide agronomic benefit to wheat in North Carolina.

Winter wheat (Triticum aestivum L.) field trials were conducted from 2013 to 2015 to evaluate effectiveness of Environmentally Smart Nitrogen (ESN) in two different physiographic regions in North Carolina: Coastal Plain and Piedmont. Trials were designed to (i) determine the effectiveness of ESN alone or in blend with ammonium sulfate compared with standard fertilizer applications; and (ii) identify optimum timing of application. At plant, all plots received starter fertilizer as urea–ammonium nitrate (UAN) at the rate of 30 lb N acre−1. An additional 105 lb N acre−1 was applied as one of six treatments in the winter (late January through early February) and/or spring (early March). Winter treatments consisted of 100% ESN, or blends with ESN providing either 75 or 50% of total N (ammonium sulfate provided the remainder). A fourth treatment consisted of spring ESN application providing 50% of the total N (the remainder from ammonium sulfate). Two final treatments provided N from UAN and ammonium sulfate, either as split application (late winter and early spring) or spring application. Compared with fertilizer applications without ESN, ESN treatments did not differ for grain or straw yield, or grain, straw, or crop N uptake in the Piedmont. In the Coastal Plain, 2013–2014 ESN treatments returned higher yields when applied in spring than in winter applications; spring‐applied treatment without ESN had higher yields than ESN treatments. In 2014 to 2015, there were no yield differences between the ESN treatments and the non‐ESN treatments. Environmentally Smart Nitrogen does not appear to provide an agronomic benefit to wheat production in North Carolina.
Weed Control in Soybean with Preemergence‐ and Postemergence‐applied Herbicides
Authors: Oliveira Maxwel C. , Feist Dave , Eskelsen Steve , Scott Jon E. , Knezevic Stevan Z.
Published: June 2017

Core Ideas

Herbicide premixes provided good (>90%) broadleaf and grass weed control in Nebraska.

Preemergence‐applied herbicide premixes with different sites of action will help manage resistance weeds.

Preemergence‐applied herbicides should be a foundation for weed management in soybean.

In the past 20 years, weed control in soybean (Glycine max) was mainly based on postemergence (POST) applications of glyphosate, which resulted in glyphosate‐resistant weeds. Herbicide‐resistant weeds warrants evaluation of new strategies for effective control. Therefore, the objective of this study was to evaluate the performance of herbicides applied preemergence (PRE) and POST on 11 agronomic weeds in eastern Nebraska. The study was conducted in 2014 and 2015 in Concord, NE. The best PRE‐applied treatments were metolachlor + imazethapyr, fomesafen + imazethapyr, flumioxazin + imazethapyr, and flumioxazin + metribuzin, which controlled broadleaf and grass weed species ≥90 and ≥80%, respectively. However, weed control with POST herbicides was more variable, ranging from 19 to 91%. The POST‐applied fomesafen and fomesafen + imazethapyr controlled ivyleaf morningglory (Ipomoea hederacea), common lambsquarters (Chenopodium album), common waterhemp (Amaranthus tuberculatus), and redroot pigweed (Amaranthus retroflexus) ≥85%. Greater soybean yields were achieved with most PRE‐applied herbicides and POST‐applied fomesafen + imazethapyr only. Metolachlor + imazethapyr, metolachlor, and fomesafen applied PRE protected soybean yields better than when applied POST. Results suggested that PRE‐applied herbicide mixtures of different sites of action are the base for controlling weeds and protecting soybean yields in eastern Nebraska.