bluuebunny/crossref_metadata_2025 huggingface dataset:
Hypothesis‐driven and field‐validated method to prioritize fragmentation mitigation efforts in road projects
Authors: Vanthomme Hadrien , Kolowski Joseph , Nzamba Brave S. , Alonso Alfonso
Published: October 2015

The active field of connectivity conservation has provided numerous methods to identify wildlife corridors with the aim of reducing the ecological effect of fragmentation. Nevertheless, these methods often rely on untested hypotheses of animal movements, usually fail to generate fine‐scale predictions of road crossing sites, and do not allow managers to prioritize crossing sites for implementing road fragmentation mitigation measures. We propose a new method that addresses these limitations. We illustrate this method with data from southwestern Gabon (central Africa). We used stratified random transect surveys conducted in two seasons to model the distribution of African forest elephant (Loxodonta cyclotis), forest buffalo (Syncerus caffer nanus), and sitatunga (Tragelaphus spekii) in a mosaic landscape along a 38.5 km unpaved road scheduled for paving. Using a validation data set of recorded crossing locations, we evaluated the performance of three types of models (local suitability, local least‐cost movement, and regional least‐cost movement) in predicting actual road crossings for each species, and developed a unique and flexible scoring method for prioritizing road sections for the implementation of road fragmentation mitigation measures. With a data set collected in <10 weeks of fieldwork, the method was able to identify seasonal changes in animal movements for buffalo and sitatunga that shift from a local exploitation of the site in the wet season to movements through the study site in the dry season, whereas elephants use the entire study area in both seasons. These three species highlighted the need to use species‐ and season‐specific modeling of movement. From these movement models, the method ranked road sections for their suitability for implementing fragmentation mitigation efforts, allowing managers to adjust priority thresholds based on budgets and management goals. The method relies on data that can be obtained in a period compatible with environmental impact assessment constraints, and is flexible enough to incorporate other potential movement models and scoring criteria. This approach improves upon available methods and can help inform prioritization of road and other linear infrastructure segments that require impact mitigation methods to ensure long‐term landscape connectivity.
Women’s Awareness of Their Contraceptive Benefits Under the Patient Protection and Affordable Care Act
Authors: Chuang Cynthia H. , Mitchell Julie L. , Velott Diana L. , Legro Richard S. , Lehman Erik B. , Confer Lindsay , Weisman Carol S.
Published: October 2015

The Patient Protection and Affordable Care Act mandates that there be no out-of-pocket cost for Food and Drug Administration–approved contraceptive methods. Among 987 privately insured reproductive aged Pennsylvania women, fewer than 5% were aware that their insurance covered tubal sterilization, and only 11% were aware that they had full coverage for an intrauterine device. For the Affordable Care Act contraceptive coverage mandate to affect effective contraception use and reduce unintended pregnancies, public awareness of the expanded benefits is essential.
Changing Awareness of the Health Insurance Marketplace
Authors: Bias Thomas K. , Agarwal Parul , Fitzgerald Paula
Published: October 2015

The Health Insurance Marketplace was designed to increase the affordability of health insurance. The success of the marketplace depends on people’s awareness and use of it. In a statewide mail survey of West Virginians, we found that respondents’ awareness of the West Virginia Health Insurance Marketplace increased from 2013 to 2014. However, large percentages of respondents continued to be unaware of the availability of federal subsidies and were unsure of their personal eligibility for these subsidies. It is essential that awareness and enrollment efforts continue and that they be expanded in novel ways to continue growth in access to health insurance through the marketplace.
Medicaid Coverage Expansion and Implications for Cancer Disparities
Authors: Choi Seul Ki , Adams Swann Arp , Eberth Jan M. , Brandt Heather M. , Friedman Daniela B. , Tucker-Seeley Reginald D. , Yip Mei Po , Hébert James R.
Published: October 2015

Objectives. We estimated the impact on cancer disparities in US states that have chosen or not chosen to expand Medicaid since passage of the Patient Protection and Affordable Care Act.

Methods. Data came from the 2013 Uniform Data System for colorectal and cervical cancer screening rates among patients of federally qualified health centers (FQHCs); the 2012 Behavioral Risk Factor Surveillance System for colorectal, cervical, and breast cancer screening rates; and the US Cancer Statistics (2007–2011) for colorectal, cervical, and breast cancer mortality-to-incidence ratios (MIRs). Dyads of Medicaid expansion decisions with cancer screening rates and MIRs were mapped using ArcMap.

Results. States that had not expanded Medicaid as of September 2014 had lower cancer screening rates, especially among FQHC patients. Overall, cancer MIRs were not significantly different by Medicaid expansion status. However, Southeastern states without Medicaid expansion tended to have higher cancer MIRs and lower screening rates.

Conclusions. Disparities in cancer screening that already disfavor states with high cancer rates may widen in states that have not chosen to expand Medicaid unless significant efforts are mounted to ensure their residents obtain preventive health care.
Higher Retail Prices of Sugar-Sweetened Beverages 3 Months After Implementation of an Excise Tax in Berkeley, California
Authors: Falbe Jennifer , Rojas Nadia , Grummon Anna H. , Madsen Kristine A.
Published: October 2015

Objectives. We assessed the short-term ability to increase retail prices of the first US 1-cent-per-ounce excise tax on the distribution of sugar-sweetened beverages (SSBs), which was implemented in March 2015 by Berkeley, California.

Methods. In 2014 and 2015, we examined pre- to posttax price changes of SSBs and non-SSBs in a variety of retailers in Berkeley and in the comparison cities Oakland and San Francisco, California. We examined price changes by beverage, brand, size, and retailer type.

Results. For smaller beverages (≤ 33.8 oz), price increases (cents/oz) in Berkeley relative to those in comparison cities were 0.69 (95% confidence interval [CI] = 0.36, 1.03) for soda, 0.47 (95% CI = 0.08, 0.87) for fruit-flavored beverages, and 0.47 (95% CI = 0.25, 0.69) for SSBs overall. For 2-liter bottles and multipacks of soda, relative price increases were 0.46 (95% CI = 0.03, 0.89) and 0.49 (95% CI = 0.21, 0.77). We observed no relative price increases for nontaxed beverages overall.

Conclusions. Approximately 3 months after the tax was implemented, SSB retail prices increased more in Berkeley than in nearby cities, marking a step in the causal pathway between the tax and reduced SSB consumption.
A Practical Method for Planning Large Number of Horizontal Wells with a Reservoir Model for a Field Development Plan
Authors: Fava Guido , Dinh Anh Viet
Published: October 2015

The most advanced technique to evaluate different solutions proposed for a field development plan consists of building a numerical model to simulate the production performance of each alternative. Fields covering hundreds of square kilometers frequently require a large number of wells. There are studies and software concerning optimal planning of vertical wells for the development of a field. However, only few studies cover planning a large number of horizontal wells seeking full population on a regular pattern.

One of the criteria for horizontal well planning is selecting the well positions that have the best reservoir properties and certain standoffs from oil/water contact. The wells are then ranked according to their performances. Other criteria include the geometry and spacing of the wells. Placing hundreds of well individually according to these criteria is highly time consuming and can become impossible under time restraints. A method for planning a large number of horizontal wells in a regular pattern in a simulation model significantly reduces the time required for a reservoir production forecast using simulation software. The proposed method is implemented by a computer script and takes into account not only the aforementioned criteria, but also new well requirements concerning existing wells, development area boundaries, and reservoir geological structure features.

Some of the conclusions drawn from a study on this method are (1) the new method saves a significant amount of working hours and avoids human errors, especially when many development scenarios need to be considered; (2) a large reservoir with hundreds of wells may have infinite possible solutions, and this approach has the aim of giving the most significant one; and (3) a horizontal well planning module would be a useful tool for commercial simulation software to ease engineers' tasks.
A New Tool Makes the Makeup Operation of Drill Collar Easier and Safer - Design and Application of Rotatable Lift Sub
Authors: Hongying Zhang , Tao He , Kaifu Mi , Yanjun Wang , Na Wang , Lianyang Zou , Yanfu Huang
Published: October 2015

As it is known to all, lift sub is a short drill string component that is temporarily connected to the top of a tool assembly that is to be lifted vertically, such as when running or retrieving a tool string.

The external profile on the upper section of the conventional lift sub is similar to that of the drill pipe, enabling the rig elevators to lift the assembled tool string safely. The conventional lift sub is made of one piece of the steel, and the bottleneck of this structure is: when the upper section is seated in the elevators, the lower part (thread section) is difficult to rotate while the drill collar is connected, which brings intensive labor force to makeup connections and run in hole. Drill collar is thick wall tubular with threaded connections, is an important component of a drill string that provides weight on bit for drilling. The drill collar, male on one end and female on the other, can be screwed together along with other downhole tools to make a bottom hole assembly (BHA). The more drill collars connected, the heavier the BHA is, the more difficult to rotate the string. Based on this, the rotatable lift sub is invented and applied; axial cylindrical roller bearings are adopted to make the lower part rotate with flexibility. After the upper section is seated in the elevator and then fixed together as the cause of weight, while the lower part can be rotated with the drill collar, which brings great convenience to the operation of makeup connections of drill collar and such downhole tools.

The successful field application of the rotatable lift sub has proven its advantages, with increased safety and efficiency.
Real-Time Data Gathering and Transmission of Fracture Treatment Operations and Micro Seismic Monitoring to Enable Optimization of Field Development
Authors: Al-Khudiri Musab M. , AlSanie Faisal S. , Bartko Kirk M. , Kurdi Mohammed S , Kashif Muhammad , Meraj Hamood
Published: October 2015

This paper highlights the tremendous impact of real-time data transmission and visualization on hydraulic fracturing, also known as "fracing." Here, we will focus on tight reservoirs. Utilizing the advanced real-time visualization system with high-resolution data transmission enables the frac engineers to achieve promising results, and ensures effective decision making and data substantiation from real-time fracing centers at their base offices.

Saudi Aramco adopted single-viewer visualization solutions to support a wide range of different operations with a single system through which Aramco users can simultaneously monitor various activities, including drilling and post-drilling activities with ease. This solution was approved to support the high supremacy of hydraulic fracking operation and their requirements by attaining the high speed of data transmission and visualization at the rate of minimum one-second data. The data transmitted all the way from the rig site to the base monitoring centers and displayed on customizable templates to meet the requirements of the data visualization with real-time calculations.

The importance of real-time monitoring micro-seismic data is the key tool to determine the frequency of hydraulic fracturing during frac operations. This type of operation needs to be verified with the simulation models, and the whole range of complex operations is made possible with the advance technique to transmit real-time data. This real-time data was used for monitoring and treating wells at the most required rate of data availability at the base where complete optimization teams utilize different simulation applications to connect direct real-time data feeds, which are used to capitalize on the industry-standard well data transmission protocol (WITSML).
An Innovative Cement Formula to Mitigate Gas Migration Problems in Deep Gas Wells: Lab Studies and Field Cases
Authors: Al-Yami Abdullah S.
Published: October 2015

Gas Migration through cement columns has been an industry challenge for many years. To control gas migration, high cement densities are required to successfully cement the high pressure formation. Formation gas/influx can migrate through the cement column resulting in gas being present at the surface.

Current high density cement formulations do not provide good gas migration prevention due to settling and increase in permeability. To solve the settling problem and reduce permeability of cement, intensive lab work was conducted earlier by Al-Yami et al. (2009).

The objective was to develop novel cement formula containing a combination of solids with different particle size distribution to minimize cement porosity and prevent solids settling. Compared to conventional high density cement weighted up with hematite, the developed cement showed no signs of settling, better fluid loss control and improved resistance against gas migration in the lab.

Saudi ARAMCO has successfully trial tested their new developed cement formula (Gas Preventing Cement) in 5 wells in 2015 for 9 5/8" casings across high pressure formation to mitigate 9 5/8" X 13 3/8" Annular leaks. This is an effort to help in minimizing gas shut-in potential and safety risks due to casing-casing leaks. The new formula was applied with good cement returns to surface and good wellbore isolation according to the conducted well flowing test. In addition, loggings were run to ensure good bonding of cement. More high pressure gas wells will be cemented using this formulation.
Prediction of Multistage Fracturing Performance in Horizontal Heavy Oil Carbonate Reservoir
Authors: Al-Mutairi Saleh H. , Al-Aruri Ahmad D. , Al-Otaibi Saud F. , Al-Subaie Abdullah M. , Park Han-Young
Published: October 2015

Horizontal oil and gas wells with low permeability might not be economic without multistage fracturing. Nevertheless, heavy oil horizontal wells instigate the additional problems of low mobility and low oil gravity. In these heavy oil prospects, multistage fracturing can increase the reservoir contact tremendously but the viscous nature of oil flowing within the matrix and through fractures may pose a challenge to the economical success of the fracturing treatments. The objective of this paper is to study multistage fracturing performance in heavy oil horizontal wells across carbonate reservoirs.

A sector model was extracted from a full field reservoir model and was then equipped with Local Grid Refinement (LGR) mesh to accurately predict the performance of multiple transverse fractures. The model was used to study the effect of several design parameters on the performance of the horizontal well. Special consideration was given to PVT data. The output of the refined simulation sector LGR model was compared with available analytical and numerical models for multistage fracturing performance predication. Finally, the resulting optimal fracturing strategy was evaluated using the full field simulation model.

This work presents an analysis and history match of actual multistage acid fracturing treatment in heavy oil field. Results of the model were important for the heavy oil field development and well placement and completion strategies.
Optimizing Production & Operation through Automated Well & Network Modeling
Authors: Das Mriganga , Naharuddin Zadil Hayat , Al-Khalid Dhuha
Published: October 2015

Raudhatain field located in North Kuwait produces hydrocarbons from over 230 wells into Gathering Center X with varying complex geometries, completions and downhole equipment. NK asset team is executing a project of modeling the entire NK production system starting with wells in Raudhatain field producing to GC-X, involving building models for the wells and the gathering surface network of flow lines.

There are numerous challenges that the NK asset team is facing in meeting production targets, including controlling water/gas breakthrough in horizontal wells. Mitigation measures include installation of inflow control devices (ICDs). Since inception a decade ago this proven technology has long been used in many oilfields around the world and is increasingly being installed in horizontal wells in Kuwait. To date there are several horizontal wells in Raudhatain field completed with ICDs.

Reservoir modeling and simulation approach is frequently used in the industry capturing the behavior of existing ICD wells. This approach uses conventional modeling tools that are typically more intricate and require expert skills in capturing the dynamic behavior of the wellbore and the reservoir which is less appealing to the operations and practicing engineers.

Limited with time and resources in this project, the NK team took a relatively simpler and fast approach in modeling existing ICD wells in Raudhatain field with the aim of enabling the engineers to capture the behaviour of the wells using existing production engineering tools at their disposal.

The approach can be summarized as follows: ➢Establishing the well performance➢Modeling the individual ICD sections in accordance to the approximate flow distribution/geometry along the horizontal well➢Matching the well with well test data

Key benefits of this approach are: ➢Enabling the engineers to quickly model the ICD wells.➢Facilitated the use of existing tools to deliver engineering models fit for use in the production system.➢Serves the purpose of high level modeling of complex ICD wells and in the future this exercise will certainly be undertaken to capture wellbore hydraulic effects.➢ICD well models are timely added into the gathering network which would otherwise have been delayed using a conventional method.
Produced Water Injection - The Challenges Faced
Authors: Bhola N , Ariaratnam G , Roth N
Published: October 2015

In this paper we will discuss the factors that influence the strategy for produced water treatment and disposal. Various aspects of the produced water treatment plant will have an impact on the water quality achieved, for example operational parameters such as interface levels, differential pressure ratios, flowrates, pressures, temperatures, etc. The required specification for either discharge or reinjection is a key factor in determining the necessary process equipment and chemicals that are needed for the separation process. For injection, the water quality needed to be achieved are often more stringent as it has limitations on solids loadings and particle size as well as oil concentrations.

In this paper we will review a detailed case study that was conducted offshore in the UK North Sea. This site was struggling to achieve the water quality needed for reinjection. The work conducted quantified the key areas that were causing the process problems and explored options such as optimising existing separation equipment as well as maximising chemical efficiency.

The case study will highlight how the overall process performance was improved once the oily water separation challenges faced were identified and understood. Improved water quality was achieved by enhancing the chemical dose rates for one chemical and eliminating the use of another chemical as well as optimising several operating parameters for different parts of the treatment process. The overall work led to reduced operation costs and reduced production time whilst ultimately achieving water quality within the required specification without affecting the export oil quality.
Planning for Uncertainties in Gas Composition: Reduce Project Risks by Early Adoption of a Robust Gas Processing Concept
Authors: Demmers Anton , Gupta Neha , Vaart Rick van
Published: October 2015

This paper demonstrates that selecting a gas processing concept that is robust against changes in predicted gas composition during the maturation of (associated) gas projects reduces the risk of schedule delays and cost creep while potentially presenting opportunities to deliver first hydrocarbons to customers earlier.

During early project phases, the availability and quality of data on the specific field to be developed are usually limited. Consequently, project teams have often been left with two options when designing gas processing facilities. The first option is to rely on old data, data from well tests of questionable quality and/or data from analogue fields, if available, in order to form the basis of their design. This brings relatively high risk of having to redesign once higher quality data become available. Design alterations may delay the schedule to first oil/gas and lead to increased costs and erosion of the overall project value.

The second option is to wait for new well test data to become available before starting work on the gas processing facilities. This approach, though preferable, can result in costly schedule delays and does not guarantee the delivery of accurate data on which to predict the gas composition and base the gas processing design.

Appreciating this uncertainty is the first step in mitigating the risk. The second step is selecting a gas processing concept that is robust against flow and compositional deviations. In this way, the design of the gas processing facilities can go ahead at a low risk before full appraisal of the field is complete. This may enable parallel project phasing by starting the engineering procurement and construction (EPC) phase for the gas processing facilities during field appraisal.

Shell believes that an effective gas processing line-up of an acid gas removal unit (AGRU) that utilises the Shell Sulfinol-X all-in-one amine technology along with a selective acid gas enrichment unit (AGEU) combined with sulphur recovery units (SRU) and sulphur dioxide (SO2) tail gas treatment provides the robustness to deal with high compositional uncertainty for the gas.

The novelty in this paper is recognising that robust gas treating line-ups such as the one described above can have operational advantages and enable developers to secure their licence to operate by meeting emission restrictions. These line-ups can also have additional project execution/schedule advantages that add value to a project.

Specifically, this paper will demonstrate that the small additional capital expenditure required for the proposed robust design is more than compensated for by the acceleration of the project resulting in an overall improvement to the net present value. Additional benefits to the project will be ease of operation, simplicity and ultra-low emissions.
Coexistence of Gas-Condensate and Volatile Oil at Pressure Higher than Saturation Pressure. Physical Explanation and Modeling Approaches. Case Study: Sabriyah Field in North Kuwait Jurassic Asset
Authors: Fava Guido , Descubes Elena , Daoud Ahmed , Sharifzadeh-Najafi Ahmad , Al-Enezi Bashayer , Al-Arouj Mutlaq , Dashti Qasem
Published: October 2015

Sabriyah and Raudhatain are the main fields producing from the Middle Marrat Jurassic formation in North Kuwait with approximately 5 km distance between the two fields. Raudhatain fluid is considered as Volatile Oil, while Sabriyah is described as Gas-condensate. 16 PVT samples from Raudhatain were analyzed and described as Volatile oil. 12 PVT samples taken from Sabriyah field where 7 samples show gas condensate behavior and rest shows volatile oil.

A key challenge in understanding the Sabriyah fluid characterization is the fact that 5 well samples that showed Volatile oil behavior are not separated from the Gas condensate wells by any apparent barrier. In addition, the initial reservoir pressure is much higher than the saturation pressure, preventing the equilibrium of those fluids.

The objectives for this study are to analyze the physical explanation of coexistent of oil and gas-Condensate in one communicated reservoir with reservoir pressure higher than saturation pressure, apply different modeling approaches to accurately describe the fluid behavior in Sabriyah field and finally capture the influence of uncertainty in the type of fluid on the production forecast.

The physical explanation for this phenomenon was investigated from different points of view: the variation of temperature, compositional variation with depth, existence of geological barriers, and facies changes. It was found that the compositional variation with depth and the change of fluids with changes of facies can provide reasonable explanation for this phenomenon. The first explanation related to compositional variations with depth is supported by the observed data that shows a strong relationship between depth and fluid type, while the temperature did not influence significantly the gas-oil phase change. The second explanation related to the concept of gas and oil charge depending on facies is supported by mercury injection capillary pressure data taken from different depth in the reservoirs, this concept improves the understanding of fluid distribution which could not be explained in previous approaches.

This paper shows the way of modeling this phenomena based on these two explanations, which honor both static and dynamic data with special reference to the effect of these different modeling approaches on the production forecast of Sabriyah field.

The near critical fluids which are the type of fluids in Sabriyah field are usually problematic to handle with Equation of State; therefore solving this particular case is expected to add technical value to reservoirs of the same type of fluids.

The facies dependence of gas and oil distribution and the way of modeling this phenomenon is an innovative view that can contribute to the description of similar fields.
An Effective Small Scale Pressure Maintenance Scheme - Conception to Implementation - A Case Study
Authors: Badusha Syed Ibrahim , Mahato Anil , De Santanu , Safar Ahmad
Published: October 2015

Reservoir Depletion is addressed in many ways across the globe with water injection being the most common method. A typical full field water injection scheme takes years for implementation, with surface players like injection facility construction dominating the project cycle and delays are not uncommon. The resulting loss in deferred production and recovery along with continuous amendments to production profiles of the field can be minimized by resorting to DumpFlooding as an easy and quick alternate.

"A" field is a satellite field of Kuwait. Bulk of production is from the thin estuarine channel sand of average thickness of 13ft within Zubair Formation. This channel system is laterally continuous as interpreted from the Isopach map and has a fairly uniform pressure throughout the field. With no aquifer support, a decrease in pressure from the initial levels of 2500 psi by around 1000 psi was observed. The production performance also deteriorated since the operational teams had difficulty keeping the ESPs on operation continuously. The size and location of the field could not economically justify a conventional water injection project. As the reservoir pressure came perilously close to the bubble point, a partial pressure maintenance scheme was conceptualized, with DumpFlooding as injection mechanism.

A systematic plan to address all the uncertainties that could have an impact on the success of the project was listed and addressed. The injection volumes and injection patterns were evaluated and firmed up by a simulation study. Various source water reservoirs were identified and water compatibility analysis was carried out to confirm the suitable injection water. Multiple single well pilots with completions from different source water reservoirs were tested. The productivity & injectivity indices of the different sources and the sink were ascertained. When the full field implementation was carried out, the team was able to take further steps with considerable confidence, having taken important lessons from each stage.

The concept proved to be successful with real benefits seen on the ground. The layer saw a gradual rise in reservoir pressure monitored by an intensive surveillance programme. A rise in pump intake pressure of ESPs ranging between 150 to 200 psi within a span of 1 year was noticed. The field started experiencing trouble free ESP operation. New horizontal producers drilled as a part of the scheme resulted in significant oil gain. A 25% increase in overall layer production was observed. The paper discusses the key milestones from conception to implementation with emphasis on the role played by each stage in the grand scheme of things. A case is thus made for considering DumpFlooding as a necessary intermediary in any upcoming water injection project.
Tracer applications in Water flooded reservoirs in North Kuwait
Authors: Tasneem Al-Twaitan , Chetri Hom
Published: October 2015

SabiriyahMauddud is a giant carbonate reservoir in North Kuwait, under active water flood using 18 inverted 9-spot patterns and 11 peripheral injectors. Water flooding operations require proper understanding of the connectivity between the injectors & producers so that the assurance on water flood sweep is properly diagnosed and corrective actions are initiated. The objective of the paper is to share the planning, sampling & integrated analysis of the tracer applications to enhance the water flood efficiency in a pattern(P- 1) in SabiriyahMauddud at the Crestal part surrounded by four nearby patterns (P-2; P-3; P-4 & P-5) & intersected with numerous faults.

Extensive data illustrating the reservoir connectivity was pre-analyzed in an integrated manner. The data covered permeability trends; openhole logs; RFT data; mapping of high perm streaks; pressure response as time-lapsed static Bottom hole pressure surveys; PVT data; oil rate & water cut trends since the start of water flood activities in 2000. Also, the salinity contrast was used to understand the water movement pathways, as low salinity sea water was injected in a purely depletion drive segment, with no mobile formation water. The diagnostics, however, could not be fully conclusive as the surrounding producers of P-1 were also receiving injection support from P-2; P-3; P-4 & P-5 (surrounding patterns). Distinctive Chemical tracers were injected into P-1 as well as surrounding P-2; P-3; P-4 & P-5, with a comprehensive sampling program at all associated producers. Continuing with sampling & tracking over a period of 2 years has helped to understand the high speed zones and inter-pattern connectivity.

Injectors of Pattern-1 were found to be in excellent connectivity with the surrounding producers, with partial support from the injectors for P-2; P-3; P-4 & P-5. The information helped to scale down the injection allowable for the injector of P-1, resulting in average reduction in water cut from 50-60% to 30-45%. Further optimization is planned in future by isolating the high perm layer from the surrounding producers during rig over jobs and even by horizontal sidetrack of producers for upper part and injectors for lower part (which is high perm zone).

Tracer information, thus, added value to the understanding of the water flood connectivity which has been duly integrated into reservoir models during history match. Also, as the way forward, the strategy has been expanded to all other patterns & even horizontal injectors and is under implementation.

Value was added to the water flood surveillance activities in North Kuwait by proving this way of diagnosing the connectivity in a challenging & heterogeneous reservoir under active water flood.
Optimize Development Strategy of Upper Burgan Reservoir Through Multilateral Well with Inflow Control Device in Raudhatain Field, North Kuwait
Authors: Chowdhuri Sankar , Cameron Peter , Gawwad Tarek A. , Madar Mohammad R. , Sharma Siddhartha Sankar , AlMutairi Moute'a Dughaim , Rajagopalan Vijay Shankar , Chellappan Suresh , Al-Ajmi Moudi Fahad
Published: October 2015

Development in drilling technology allows horizontal and multilateral wells to increase hydrocarbon recovery and accelerate production from high water mobile reservoir by increasing the reservoir contact surface. In coning situations, such as production of oil reservoir with a bottom aquifer, multilateral wells reduce the coning affect and hence prove to be more cost effective. To address these challenges, first multilateral well with Level-4 junction combined with Inflow Control Device (ICD) was planned, designed and drilled in Upper Burgan Reservoir of Raudhatain Field, North Kuwait.

The Upper Burgan Formation is layered sandstone–shale sequence deposited in deltaic settings having very fine to fine grained marine influenced channel sand as reservoir rock. Geosteering and evaluating these wells is very challenging without using a proper LWD technology. Indeed, the resistivity anisotropy is a major issue, especially if it occurs with influence of other bed boundary effects like resistivity of adjacent beds or polarization horn effects. Water coning issues in the field makes it even worse to interpret the resistivity data as they become spiky. To overcome these challenges the drilling bottom hole assembly was designed in the way to include the distance to boundary and the new Multi-function LWD sourceless technology. The capture gamma ray spectroscopy and formation sigma in real time has improved the petrophysical evaluation of this complex resistivity environment with mixed lithology in wells that are difficult or even costly to consider TLC wireline logging.

The Lower Lateral of 2145′ with 8½" hole diameter was drilled through very fine grained sandstone in UB3 Lower zone and completed with 5" open hole ICD. The Upper Lateral of 1757′ was placed in UB3 upper zone having very good reservoir quality. This lateral was completed by 4½" open hole ICD. The production is comingled as the pressure difference between the two laterals was not more than 100 psi. The well operated under Electrical Submersible Pump (ESP) produced more than the estimated rate of oil during initial production.

The success of the well not only addressed the issues related to enhancement of oil production and premature water break through but also opens up a new chapter of drilling multilateral wells in coming days in Raudhatain Field, North Kuwait. The paper covers the main challenges while well placement during geosteering to stay in the best quality of reservoir rock in structural and depositional complex settings and with the smart completion design for increase oil production and rate of recovery.
IOR/EOR Monitoring Onshore with Frequent Time-Lapse Seismic
Authors: Lopez J. L. , Przybysz-Jarnut J. K. , Hornman J. C. , Mateeva A.. , Zwaan M.. , Potters H..
Published: October 2015

With the recognized cost and complexity of IOR and EOR projects onshore, there is a significant risk of projects not meeting their NPV or production targets, unless cost-effective well and reservoir management plans are in place to mitigate such risks. Time-lapse seismic could provide important and timely information to diagnose and remediate areal conformance issues, if the time-lapse data is of high enough quality and low enough cost to be acquired on a frequent basis. We review the business case, expected value, and affordability of seismic monitoring in IOR/EOR projects and the new technologies that may be used for this purpose. We illustrate these ideas with a case study from the Peace River heavy oil field in Canada, as it is implemented today to monitor steam injection in a relatively shallow reservoir and how it could be implemented in the future to reduce cost and preserve value by judicious adjustment of the frequency of seismic monitoring. We also comment on the challenges and technology options for monitoring of deeper reservoirs.
2004–2014: A Decade of Drill Pipe Grades and Industry Standards Evolutions to Address Increasing H2S Challenges
Authors: Flores Vincent
Published: October 2015

Hydrogen Sulfide (H2S) can interact with steel tubular, such as drill pipe,and through the unfavorable combination of different factors a crack can initiate in the material and propagate until catastrophic failure, even with stresses largely below the yield limit of the material. The combination of tubular failures due to Sulfide Stress Cracking and the rising HSE concerns when dealing with sour gas has led the industry to develop new grades of drill pipe with enhanced resistance to SSC.

Material selection for drill pipe in a sour environment is significantly complex, mainly due to the absence of dedicated international standard. Nonetheless, at a regional level the "Industry Recommended Practices" Volume 1 has been published in 2004 in Canada. The standard was created to insist on people safety, and provide specification and guidelines to manufacturers on material properties, quality control, testing and inspection of drilling products intended to be used in critical sour wells.

Sour Service Drill Pipe as defined in the IRP have been used for a decade in Canada, as well as in other regions and continents, along with a variety of other proprietary Sour Service grades of drill pipe and BHA. This paper proposes a review of different field cases in the Middle East and Asia, as well as an outlook of the different practices for material selection and qualification guidelines which have emerged since the past 10 years.

More recently, with the increasing demand of domestic gas in different part of the world, some highly sour oil and gas reservoirs are being explored with H2S contents beyond what could have been imagined a decade ago. To explore, appraise and eventually develop such fields, most of the time combined with complex well profiles or deeper reservoirs, significant technical challenges need to be addressed regarding drill pipe integrity and operations safety. This paper proposes a non-exhaustive review of the newest emerging industry trends as far as international standard guidance, regional normative initiatives, and new steel developments.
Laboratory Study on Steam and Nitrogen Co-injection for Mid-deep Heavy Oil Reservoirs
Authors: Wang Cheng , Zhong Liguo , Li Jianping , Chen Gang , Zang Ye , Wei Fang
Published: October 2015

Surface steam injection is the most common enhanced oil recovery (EOR) technology used in heavy oil production. Nevertheless, limits exist due to heat loss for deep reservoirs. In the process of steam injection, adding a certain amount of nitrogen, which can reduce heat loss, maintain formation pressure and expand steam chamber, can effectively improve the development efficiency of steam injection.

In this research, high-temperature-pressure pressure/volume/temperature (PVT) measurements and sand pack flooding experiments have been operated for heavy oil of the target reservoir in Bohai Oilfield, China, observing effect of nitrogen on property of heavy oil and steam and nitrogen co-injection on displacement efficiency and optimizing gas-water ratio during the co-injection.

The results of PVT measurements indicate that the change of heavy oil viscosity is complex with the varying amount nitrogen dissolved. The reason is that dissolved nitrogen can reduce heavy oil viscosity on one hand; on the other hand, nitrogen can compress oil increasing its viscosity. The viscosity of heavy oil with dissolved nitrogen decreases significantly under low temperature and pressure (80°C, 15MPa), and the maximum viscosity reduction rate is 28%. Along with increase in temperature and pressure (150°C, 25MPa), the viscosity reducing effect becomes worse, especially at 150°C, the viscosity of heavy oil with dissolved nitrogen increases, on the contrary.

The results of sand pack flooding experiments reveal that adding nitrogen during stream injection can improve oil displacement efficiency significantly. However, the increase of oil displacement efficiency is different with the varying gas water ratio; therefore, optimizing gas water ratio has a great influence on displacement effect in steam-nitrogen co-injection process. There is an optimal gas water ratio in the process, which is correlated with temperature. For example, the optimal gas water ratio is around 50 and 100 respectively while temperature of 200°C and 300°C.

The key of mid-deep heavy oil reservoirs development using steam-nitrogen co-injection technology is gas water ratio optimization, and while optimizing gas water ratio properties of heavy oil, formation conditions and injection conditions, and many other factors should be taken into account. This research provides a direction to choose the optimal gas water ratio in the steam-nitrogen co-injection process.
Piloting Wireline Coring Technology in Challenging Unconsolidated Lower Fars Heavy Oil Reservoir, Kuwait
Authors: Mukherjee P.. , Al-Bader M.. , Peres J.. , Al-Matar B. S. , Kumar P.. , Choudhary P. K. , Al-Khamees W. K. , Stockwell M..
Published: October 2015

Coring reservoir rock has been an integral part of any oil & gas operator. With a vertically stacked multiple reservoirs in Kuwait stratigraphy cores are thus taken in various depth ranges from few hundred feet to higher than ten thousand feet. Wireline Coring technology, which has been successfully applied in various parts of the world, was found to be an alternative to cut down on rig time and maintain good quality of cores. Heavy oil shallow unconsolidated reservoir of Lower Fars was chosen to be tested with this innovative technology. This reservoir is as it is challenging for coring due to its highly unconsolidated nature with high intergranular porosity coupled with the issue of gravity settling of heavy oil which limits the individual core intervals.

The CorionExpress® technology of NOV uses a PDC core bit which has a wireline- conveyed drilling insert to convert the core bit to drilling mode in matter of minutes. This helps in taking multiple cores with intermittent drilling without the need to take the string out. 140' of core was cut in continuous runs with drilling of intermediate shale and drilling to the final depth of the well successfully without any need to take the assembly out of hole. There was substantial time saving of about 30% in rig operation for coring and drilling even in this shallow reservoir where normal tripping time is much less. Recovery percentage was satisfactory considering the technology was applied without a huge advantage of past experiences and lessons for the conventional coring for the same reservoir.

Gaps and lessons learnt indicated further scope to streamline the catcher and bit design for better recovery. It also requires rethink on operating procedures particularly in wireline rig up & rig down and core handling rig up & rig down for time saving. However, each of these factors need to be tailor made to the reservoir quality that is to be cored. This paper illustrates the thoughtful mix of technology, innovative techniques and proper coordination by aligning all concerned has helped in meeting the challenge of coring unconsolidated sand and it's processing to deliver a geologically acceptable core for laboratory studies.
Innovative Use of Mixer Design for Efficient Brine and Produced Water Handling
Authors: McPherson R.. , Sabey J..
Published: October 2015

Through years of research and development, ProSep has brought to market a family of mixers for use in practically every application where separation of phases or constituents take place. In produced water applications, ProSep has incorporated a series of modulating mixers along with another proprietary process technology, the CTour Process, to provide a compact solution for new build as well as retrofit / debottlenecking applications. The CTour Process is the injection of natural gas condensates into the produced water treatment line for an in-situ extraction of residual OIW. The ProSep series of modulating mixers, along with our series of chemical injection mixers, provide the efficient mixing needed to achieve low sheer, homogenous fluid mixing of the condensate to aid to the extraction of PAH molecules and dissolved BTEX components as well as dispersed hydrocarbons. The modulating feature of the mixer allows for a maintained and consistent low differential pressure under varying flow rate conditions.

This same mixer technology can also be applied on the crude oil treating pipeline using our ProMix – for chemical injection of de-emulsifiers, corrosion inhibitors, and scale inhibitors – and ProSalt – wash water injection mixer – products. Both mixing systems allow for cost savings with regard to chemical and wash water usage and injection. Additionally, the homogenous mixes created allow for more efficient downstream process equipment, such as dehydrators and desalters, with less oil reporting to the brine water effluent, therefore reducing the burden on other separating technologies in the process. These unique designs offer efficient mixing over high turndown due to their ability to modulate, require less pressure differential for operation, provide a more homogenous mixture over a shorter distance, and provide a narrower droplet distribution curve.
Extending the Vitality of a Mature Oilfield Using Well Placement Technology: A Case History of 10 Years Innovation and Commitment, Junggar Basin Northwest China
Authors: Yang Kun , Du Hongling , Zhang Yi , Huang Lei , Zeng Yanqiang , Wu Congwen , Lin Xin , Kok Jeffrey , Wang Dahai , Wang Yong , Koon Lee Tow
Published: October 2015

Luliang oilfield has been in production since 2001 and was originally developed from vertical wells. To arrest production decline, operators embarked on a horizontal drilling campaign in 2006 to achieve ultimate field recovery from remaining oil. A proper geosolution to optimize reservoir exposure while maximizing distance from bottom and edge-water was recognized as the key for success in this field.

From 2006 to 2015, the 10 years of field development was sustained through a close collaboration between the operator and service provider. However, production reviews indicate that the Luliang oilfield is approaching the end of its field life as the main underground reserve is drained away. As this mature oilfield becomes increasingly difficult to develop, well placement technologies become increasingly critical along with the commitment to service quality. With the challenge increasing, the well placement strategy and solutions must be reformed as well. Innovative use of well placement technology and workflows are crucial to ensure service quality while balancing drilling costs within the margin of economics.

From 2006 to 2014, a total of 200 horizontal wells were successfully constructed, achieving net-to-gross over 94% and improving the field's recovery efficiency by over 96%. Both productivity and cumulative production of horizontal wells were significantly enhanced compared to the original objectives. In 2015, 14 horizontal wells are on going; thus, after 10 years, the extension of this mature field's vitality continuous to press on.