bluuebunny/crossref_metadata_2025 huggingface dataset:
Improving Cycle Time to Deliver Perforation Charges for Unconventional Fracturing Operations
Authors: Alulait Mohammed , Kurdi Mohammed
Published: October 2019

This paper overviews the application of Lean Six Sigma (L6S) framework and principles to reduce overall cycle time needed to deliver perforation charges for rig-less unconventional well sites. As the unconventional program at Saudi Aramco embarked on a number of shale plays around the Kingdom, the number of fracturing stages increased sharply year on year requiring tremendous efforts to improve operational efficiency. Perforating charges are delivered to rig-less completion sites to be used in multi-stage fracturing of unconventional horizontal wells. These charges are critical for use in several well completion operational applications that are essential for establishing productivity of wells. The perforating charges are inserted in perforation guns or isolation devices, which are lowered to predetermined depths in drilled wells. The tools are subsequently triggered with an electronic signal from the surface controlling cabin to activate the Bottom Hole Assembly (BHA) tools. In an effort to reduce operational Non-Productive Time (NPT), Lean Six Sigma (L6S) was utilized. L6S is a combination of two exclusive expert knowledge areas that were employed to remove excess waste in the business process of delivering perforating charges to well sites (Lean) as well as to improve success prospect in the repetitive operation of perforating charges delivery (Six Sigma). Lean Six Sigma is a proven recipe to substantially enhance business processes through the implementation of a multitude of various tools and methodologies that ultimately aim to achieve predetermined improvement criteria. The deployment of the study's recommendations has subsequently reduced NPT drastically in relation to perforating charges delivery to almost nonexistent levels as detailed in the paper. With the aforementioned increase in the number of stages yearly, the number of well intervention jobs requiring perforating charges is expected to rapidly increase annually due to the high demand for these types of rig-less operations. By reducing NPT, there will be significant cost savings year on year that will be realized as a result of L6S application.
Facies Analysis Using Biostratigraphy Data and Also Development and Controlling Factors of Miocene Carbonate Buildups, Central Sulawesi
Authors: Putu Putu Yoga , Dzaki Darojatun Fakhrul , Luqman Luqman , Rizaldy Rizaldy Rahadian , Ricky Ricky Helbet , Sartika Sartika Anastasia , Waris Waris Budi , Junaedi Junaedi , Rahmad Rahmad Wibowo , Sugeng Sugeng Haryanto
Published: October 2019

Quantitative analysis of facies in a complex depositional environment is have some difficulty in terms of ability to constrain the data available into easily recognizable and reproducible facies types. One of the most challenging environments is the shallow water carbonate depositional system. Using subsurface data, a facies class of Tertiary carbonates of Banggai Basin was established to allow reproducible facies descriptions by multiple workers. The analysis based on core data from Research area (about 2,000 feet of core from five wells)

Tertiary subsurface carbonates of the Research area, range in age from Late Miocene to Early Pliocene and are comprised of diachronously deposited shallow water platform carbonate build-ups and associated with detrital carbonate sediments.

Time equivalent carbonates of the Mentawa member Limestone, showing the same range of environments. On the basis of faunal content, grain types, sedimentary texture, and sedimentary structure, Autochthonous facies types represent reef margin, platform interior, and slope environments ranging from shallow-water, reefal boundstone and rudstone to planktonic foraminifera wackestone and packstone. Allochthonous facies represent grain-dominated, detrital facies types, intercalated within mud-dominated to graindominated facies types; rich in planktonic foraminifera.

Age diagnostic, large benthic foraminifera (LBF), planktonic foraminifera, and calcareous nannoplankton enable the correlation of subsurface data and allow high-resolution sequence stratigraphic correlation throughout the research area. Integration of subsurface data leads to more insightful and realistic geological models of subsurface stratigraphy. The sequence stratigraphic development of the subsurface Paleogene in Research area, Central Sulawesi, was define using well cuttings, core data and wireline logs tied into largely published biostratigraphic and available seismic data.

Large benthic foraminifera assembladges used for detailing depositional environment also associated with reef connected environment. Diagenetic process indicating creation and destruction of carbonate porosity, due to presence of marine, fresh water, pressure and temperature that present in term of tectonic and subsidence. Some of the micritization, recrystallization, and neomorphism .
Preparing for Decommissioning: Development of Inspection, Maintenance, and Repair IMR Strategy for Inactive Offshore Platform
Authors: Suputra I Made , Junedi Karyadi , Putra Girindra Fajar
Published: October 2019

Referring to the Indonesian Ministry of Energy and Mineral Resources (MEMR) Decree No. 15 of 2018 concerning Post-Operation Activities in Upstream Oil and Gas Businesses and the SKK Migas Working Guideline No. 040 (PTK 040) Revision 01 on the Abandonment and Site Restoration (ASR), all Production Sharing Contract (PSC) contractors in Indonesia are required to carry out the ASR operations when production ceases, and to establish and contribute to an ASR fund. Prior to carry out the ASR operations, PSC contractors must submit an ASR program plan and cost estimate to SKK Migas for approval. As a mature oil and gas field of which its offshore platforms were mostly installed in the 1970’s and 1980’s, PT. Pertamina Hulu Energi Offshore North West Java (PHE ONWJ) must be ready to face challenges regarding ASR operations and platform decommissioning. It is anticipated that during the strategic planning phase, PHE ONWJ will deal with many uncertainties and unknowns, including the asset integrity of inactive platform during idle time prior to decommissioning execution, which may lead to high decommissioning cost. Inactive platforms tend to get low priority in annual Inspection, Maintenance and Repair (IMR) activities. Meanwhile, the availability and quality of asset integrity data is crucial to reduce the uncertainties and to identify the unknowns. This paper mainly discusses the efforts to initiate the IMR strategy for inactive platforms in PHE ONWJ. An optimum IMR strategy for inactive platform in ONWJ field has been developed to ensure the availability and quality of the data as feeds for decommissioning projects. With comprehensive data, it is expected that PHE ONWJ can suppress the uncertainties, identify the unknowns, and optimize the decommissioning project costs.
Revisitting Cisubuh Formation in Onshore North West Java Basin; New Analysis from Seismic Stratigraphy, Geochemistry, and Subsurface Perspective; Implication for Petroleum System and Shallow Target Hydrocarbon Exploration in Northwest Java Basin;Case Study Randegan Field and Mt. Kromong Area
Authors: Ginanjar Aji Rahmat , Anggraeni Esti , Subhan Muhammad , Aditya Adzuhri , Suhartanto Ibnu , Wibowo Wisnu , Hasani Nurul
Published: October 2019

Onshore Northwest Java Basin (NWJB) is one of the proven hydrocarbon basin in Indonesia. Conventional Play for this basin are limited to deep reservoir target such as Parigi, Cibulakan, BRF, TAF and Jatibarang Formation. This lead to high cost for drilling. This Paper present new insight on Shallow target with less than 1000 m and proven as good reservoir.

Previous study show that Cisubuh Formation is not a reservoir in many regional stratigraphy chart; it is a regional seal in onshore NWJB. This Formation contain only shale with intercalated sandstone in previous study. The method in this study is detail subsurface mapping of Cisubuh Formation in onshore NWJB including Seismic inversion analysis from seismic data to detect hydrocarbon anomaly, combine with lithological description from cutting and integrated with outcrop data and geochemistry data.

Sequence stratigraphy and lithological description is use to make more accurate stratigraphic colomn of Cisubuh Formation. The result show there are Carbonat buildup in Cisubuh Formation, transgressive sand that have good reservoir property and conglomerate. Moreover, from outcrop study it show that Total Organic Carbon from 17 sample have a value 0,27 - 4,43%, it means Cisubuh Formation have a low-very good candidate as a source rock. From Pirolysis Rock Eval Analysis show that this formation have Tmax 331-557° C with Hydrogen Index 3-338 H/g. That means that the sample from this Formation is mature-over mature and from Hydrocarbon index this formation categorized as gas prone and oil prone.

Drilling of KYM-01 well proving that Cisubuh formation is a good reservoir, it produce two MMSCF gas from Cisubuh interval. Optimizing this sudy will help for future development on many oil fields on onshore NWJB, shifting the paradigm from depth reservoir target
Wettability Study of Mixed-Wet Carbonate with Multiple Pore Systems Using Advanced In-Situ MRI Technologies
Authors: Gao Jun , Kwak Hyung T. , AlSinan Marwah
Published: October 2019

A clear description of the wettability of carbonate rocks poses numerous challenges due to its non-uniformity and uncertainty caused by complex pore systems and weak fluid/rock interactions. Aging in the crude oil and spontaneous brine imbibition of core samples in the laboratory constitute essential steps of wettability restoration, wettability measurement, and oil mobilization. Various aging durations are used to restore the carbonate wettability by researchers. The imbibed oil/water quantities in the Amott test are sometimes in the range of several percentages, and it is not clear if the fluids contact the whole core. This study investigates how the wettability evolves during again and how the imbibition develops in reservoir carbonate rocks using nuclear magnetic resonance imaging techniques.

The carbonate core samples with typical multiple pore systems were first saturated with crude oil at different irreducible saturation by centrifuge and aged for different durations. Then they were immersed in deuterium oxide (D2O) with two ends open (TEO) at an elevated temperature for spontaneous imbibition. The aging and spontaneous imbibition processes were monitored by a 1D magnetic resonance imager either by a standard probe or a high temperature and high pressure core holder. A set of nuclear magnetic resonance measurements were conducted for any wettability alteration and oil/brine imbibition front propagations.

NMR measurements during oil saturation and aging of three carbonate reservoir core samples indicate that the significant wettability change occurs after the oil flood while further aging continues to alter the wettability on a smaller scale. Low oil saturation has less of an effect on the wettability than high oil saturation. The brine imbibition fronts were found to develop from both ends or one end only, or there could be no apparent fronts. After the fronts propagate across the samples, a significant amount of brine continues to imbibe globally. The high permeability macro pore dominated samples appear to have significantly higher total brine imbibition than the low permeability micro pore dominated samples from current experimental results. Lower initial brine saturation impedes the imbibition with negligible effects on the final amount. Aging does not have appreciable effects on the brine imbibition for the samples studied.

The direct observations of wettability evolution during aging and brine spatial propagation during brine imbibition by NMR under reservoir conditions provide novel information about carbonate wettability, which assists in better wettability characterization and enhanced oil mobilization by wettability alteration.
Flowing Material Balance Analysis and Production Optimization in HPHT Sour Gas Field
Authors: Hidayat Azis , Febrianto Dwi Hudya , Wijayanti Elisa , Nurhajj Diniko , Sujai Ahmad , Nurak Jufenilamora
Published: October 2019

As one of gas field producers located in South Sumatra Indonesia, the S field produced 70 MMSCFD as its peak production. It is a high pressure and high temperature gas impurities of 30% CO2 and 100-ppm H2S. The field has been producing since April 2010, with current recovery more than 50% of initial gas in place. Utilizing initial estimated OGIP (Original Gas In Place), the gas deliverability was predicted to last only until 2022. There are high uncertainties in estimating accurate reserves value due to lack of reservoir data such as reservoir pressure and SCAL (Special Core Analysis). Therefore, additional information such as SBHP (Static Bottom Hole Pressure) survey data and well optimization are essential to be conducted to narrow the uncertainties in reserves estimation and gas deliverability.

Apparently, in 2018 and 2019 during CPP (Central Processing Plant) shut down for preventive maintenance activity, SBHP survey could be performed. Additional pressure data was utilized to update the OGIP analysis by combining several methods such as p/z analysis, flowing material balance, rate transient analysis and history matching of dynamic model analysis. The analysis shows conclusive result that there is significant increase in the OGIP and reserves, estimated 16% of additional gas reserves.

To support enhance gas deliverability, the production network model was then created to evaluate existing production method. This updated system analysis showed significant bottleneck at the existing production system that limiting the production rate from the wells. As part of debottlenecking endeavor, temperature survey on the production system was employed to overcome the limited availability of pressure survey points in the system. Furthermore, the successful debottlenecking activity combined with temperature drop analysis resulted in 20% additional gas deliverability.

This integrated evaluation and optimization also prolong the field lifetime until 2025. This paper describes some of the challenges and lessons learned during the evaluation and optimization in the high pressure and high temperature sour gas field.
Successful Integration of Sampling While Drilling and Geomechanical Analysis in Unconsolidated Reservoirs: A Case Study from Sarawak, Malaysia
Authors: Ng Alex Kwai , Ong Isaac , Khalid Aizuddin , Samsudin Basir , Kamaruddin Aizat , Hardikar Nikhil , Pragt Jos , Khaksar Abbas
Published: October 2019

Sampling While Drilling has been successful in recent times covering numerous applications including difficult boreholes, horizontal wells, influencing drill stem test plans, cost savings in marginal fields, high sample volume collection, aid in quantifying non-hydrocarbon content for facilities design and deployment in carbonate under total losses with pressurized mud cap drilling conditions.

This case study discusses one more application, which is in weak unconsolidated sands of a field located in Tatau, Sarawak, Malaysia. The principal objective of the sampling-while-drilling run discussed in this paper was to collect representative water samples from an aquifer, the laboratory analysis of which would yield invaluable information about compatibility for future water injection. The secondary objective was to collect low contamination single-phase oil samples if the well penetrated hydrocarbon reservoir layers at virgin pressure. Determining fluid gradient was an inherent requirement as well.

This paper describes the challenges, best practices and learnings following the deployment of this technology in a deviated infill well in a mature oil field with sanding history and multiple layers of poorly consolidated sandstones with uncertainties on the pore pressure, due to production from the field and adjacent fault blocks that might have a certain level of connectivity.
Upstream Corporate Database Management Collaboration Using GIS
Authors: Wiyadi Raditia Muhammad , Syahnur Yudi , Supriyadi Yuly
Published: October 2019

Today's exploration, production and operation in the oil and gas industry dealing with data in various types of format. Integrating these diverse types of data are difficult and some of the data might be scattered in the employee's personal computer. The initial concept of collaboration database management is to create comprehensive upstream database system in an integrated portal to handle upstream data information in a relevance format based on historical and up-to-date representation data in the company. The core of data visualization is mainly supported by map and web services that is connected to multi-database including Professional Petroleum Data Management (PPDM), geospatial, and lynx application. To distribute web and map services, a comprehensive script was created to transfer information within the web portal and optimize its functionality. There are some challenges of building an integrating platform of lynx and geographic information system. From the phase of development, dealing with data duplication, consolidate between data and application, and integrating web and map services are the main challenges of our methodology. To handle these issues, a primary key between technical data and database is defined to correlate a relation between database and application reading and deploying metadata from the source to the web portal. As the result, the collaboration data mangement was successfully developed and deployed into company system. Map, table, and report section are well established and optimized with functions that we built during the development. Both map and upstream data web services were linked to the web portal to open seismic and well section. Users now have a portal to find their data information and visualize it in the same window.
Integrated Artificial Neural Network and Object-based Modelling for Enhancement History Matching in a Fluvial Channel Sandstone Reservoir
Authors: Vo Thanh Hung , Sugai Yuichi , Nguele Ronald , Sasaki Kyuro
Published: October 2019

Modelling accurately lithofacies and petrophysical properties is an important yet challenging process especially at the beginning of exploration and production from hydrocarbon reservoirs. However, the limited amount of well data and core data are the main issues facing conventional modelling processes. In this paper, Artificial Neural Network (ANN), Sequential Gaussian Simulation (SGS), Co-kriging and object-based modelling (OBM) were integrated as the enhancement framework for lithofacies and petrophysical properties modelling in the fluvial channel sandstone reservoir.

In the OBM, multiple fluvial channels were generated in the lithofacies model. The result of this model represented all the characteristic of the fluvial channel reservoir. The model was then distributed with channels, crevasse, and leeves depositional facies with background shale. Multiple geological realizations were made and cross-validation to select the most suitable lithofacies distribution. This model was cross-validated by modelling the porosity and permeability properties using Sequential Gaussian Simulation.

Thereafter, the modelling process continued with Artificial Neural Network. Petrophysical properties (mainly porosity and permeability) were predicted by training various seismic attributes and well log data using the ANN. Applying the co-kriging algorithm, the predicted ANN model was integrated with OBM simulated lithofacies model to preserve the fluvial features of the geological system. To achieve full field history matching, the final geological model was upscaled to serve as input data in dynamic history matching.

An excellent and nearly perfect history matching with a least mismatch was obtained between the measurement and simulated bottom hole pressure from well test and production history. The results indicated that an efficient integrated workflow of ANN and other geostatistical approaches are imperative to attaining an excellent history matching.
Key Parameter of Successful Matrix Acidizing to Combat Fines Migration in Gravel Pack Wells
Authors: Primasari Indah , Abidiy Izzad , Ismail Taufiq , Wijaya Geraldie Lukman , Hadi Aen Nuril , Yasa I Made , Luiren Bernardinus Andrie , Fuad Muhammad , Merati Putu Astari , Jayadi Agus , Akbari Aulia
Published: October 2019

In common practice, gravel pack completion is beneficial as sand control in a typical unconsolidated sandstone reservoir. However, with poorly sorted sand grains, fines migrate and deposit at the gravel-pack matrix, causing permeability reduction and hence, decreasing well productivity. Matrix stimulation has been proven to remove the fines blocking the pore throat. The desired solution has been carefully selected to have prolonged well production. Organic clay acid is chosen for to its ability to have deeper penetration and to create a thin coating on the pore surface to prevent fines migration. Laboratory testing and field application were performed in parallel. A core flood test with reservoir core samples showed a result of 111% regained permeability. Ten treatments were conducted and showed good results. The productivity index increases 10 times on average. From those experiences, a benchmark was identified, which factor determines the success of a treatment. This paper presents the project preparation and execution, key reasons to success, and the way forward.
Approach to Establish Well Network Debottlenecking Using Surface Well Testing & Pumping Spreads in a Complex Network System in Mature Fields, Rajasthan, India
Authors: Pandey Arpita , Ranjan Amit , Kumar Manish , Dangwal Gaurav , Maniar Chintan , Raju Pruthvi , Agarwal Paresh , Nagar Ankesh
Published: October 2019

Cairn Oil & Gas in Joint Venture with ONGC, is the operator of contract area RJ-ON-90/1 in the state of Rajasthan, North West India. MBA fields (Mangala, Bhagyam and Aishwarya Field) comprise of more than 565 wells. Produced liquid from these wells is transferred to Mangala Processing terminal (MPT) where liquid from each of these wells is collected and processed. MPT processes ~11,00,000 BLPD and separated water is re-used for water injection for pressure maintenance and power fluid for jet pump artificial lift. This requires stringent separation procedures to maintain injection water quality.

With the terminal operating at the limit of its processing capacity and high field water cut, maintaining oil production with high liquid handling posed a big challenge.

The objective was to prove the concept of addressing liquid handling constraint and optimizing oil production by utilizing standalone separation and pumping systems. It was anticipated that bottlenecking in the lines was causing high backpressure on the wells which led to substantial decrease in well liquid production. A network model was created which confirmed this. This paper describes the approach used to establish a standalone set-up for header pressure reduction and increased liquid handling using surface well test and pumping facilities.

The network model indicated that for an increase of 1 bar pressure in production header, there was a substantial loss in oil production from each network of MBA field. For example in Mangala Cluster A, this resulted in ~ 400 BOPD of loss in oil production.

Later an idea was developed to take out ~10,000 BPD liquid from production header line of a network and the same was separated using standalone well test & pumping spread. It was planned to pump oil back into production header and use the produced water for Jet Pumping application and remaining water to be pumped in nearby injector. The entire operation was planned with 2 standalone surface well test spread and pumping units.

Post achieving success in Mangala field the same idea was implemented in Aishwarya field where the main objective was to knock off the gas from the system along with liquid reduction from the production header which ultimately reduced the back pressure on each of the well in the pad.
Dynamometer Card Classification Using Case-Based Reasoning for Rod Pump Failure Identification
Authors: Wibawa Ramdhan , Handjoyo Teguh , Prasetyo Joko , Purba Monas , Wilantara Dedi , Dongoran Japet , Gunawan Gunawan , Negara Ari
Published: October 2019

Sucker Rod Pumps (SRP) have been extensively utilized in the Duri field Heavy Oil Operations Unit (HOOU) for more than 6000 production wells. Approximately 2000 of these wells are equipped with dynamometer online that generates a daily dynamometer card (DC). Historically, the pump cards evaluation has led to the identification of several mechanical pump issues such as a traveling valve and standing valve leak that directly impact production.

One step of the traditional process to identification of rod pump failure is based on a manual pump card shape analysis performed for individual wells by different engineers throughout production history. To improve efficiency and reliability of shape analysis, Artificial Intelligence-based data analysis has been recently integrated in the oil and gas industry. This article proposes an approach to pump card classification, developed by the Integrated Optimization Decision Support Center, using a modified Case-Based Reasoning or computer reasoning by analogy approach where new problems are solved by comparison to analogous problems solved in the past.

The proposed methodology begins with definition of a reference DC for every known type of mechanical failure. The reference cards define the analogy set. Actual pump cards are then normalized and compared for similarity against each reference card or analogy using Euclidean distance measure between the actual and reference cards. For each actual pump card, the output of this approach is a set of similarity scores which indicate the pump failure type corresponding to references card shape, if any. The analysis is enhanced through the addition of rules based on pump operational parameters that result in specific pump failure signals. The methodology has been verified against DC evaluations from Subject Matter Experts (SME) and is demonstrated to provide robust pump failure signals more efficiently than by manual interpretation of DC for a series of individual wells.
Composition Based Gas Optimisation through Integration of Oil and Gas Field to High Grade Project Economics: A Case Study
Authors: Tan Kok Liang , Bt Beserdin Nur Hafizah , Bansal Rajive
Published: October 2019

With the increasing energy demand and call for cleaner energy, industry has ventured out for challenging environment such as deepwater and unconventional natural gas resources. While new development is necessary, improvement in gas supply can also be achieved by relooking into the current system. Currently, associated gas produced from oil well are mainly used in petroleum operations, while the remaining gas are either flared or vented to the atmosphere. Inefficient usage of associated gas which has high heating value impose a great value leakage to the company.

This paper introduces a new concept that demonstrates more efficient usage and monetization of gas by utilizing associated gas and non associated gas based on its composition instead of volume and sales agreement. The value addition of this new concept was evaluated across the process chain from the upstream operator, host authority, to the downstream plant processing and end product at customer level, using a case study at Field A and Field B.

Field A is a brownfield which utilizes produced associated gas for petroleum operations including gas reinjection. Field B is a non-associated gas green field which is tied in to Field A’s processing facilities prior to gas export. Both gas from field A and field B were evaluated based on their gas composition, gross heating value and customer requirement to determine the best option of gas utilization to maximize its value. Feasibility study was carried out to ensure the practicality of the job execution and at the same time commit to the legal and sales requirements.

Field A and B belongs to the same PSC, and gas sales are purely based on the heating value and contractual volume requirement. Hence, Field B lower heat value gas can be used for injection provided that the similar volume was replaced for sales. The gas swapping for optimization can be conducted through simple flowline modification with minimal cost. A portion of gas from field B will be directed for gas reinjection at field A, while the associated gas at field A originally intended for injection will be utilized for sales. Injecting gas with leaner hydrocarbon composition will not hinder the oil recovery efficiency of field A. However, gas sales using associated gas from field A allow additional 11% profit gain for the operator from existing scenario. The products of processing the swapped associated gas will reap more profits to the downstream sector, as the gas has higher ethane, propane, and butane molecules.

In the current situation, existing fields have always considered gas utilization individually. There is potential for all fields to utilize gas more effectively to increase the economic value of the field and downstream facilities.
Complex Approach to Optimize Completion and Well Placement Strategy for Unconventional Gas Wells: Marcellus Study
Authors: Nikolaeva Alfiya , Boyer Charles M. , Xu Lili , Arroyo Kenneth
Published: October 2019

Even with the current development of unconventional reservoirs in the United States, where tens of thousands of wells have been drilled and completed, there is not enough understanding of the production and successful completion drivers in unconventional plays.

The Marcellus shale is a naturally fractured formation, and it is vital to account for the natural fractures during a simulation study. A discrete fracture network (DFN) model and a 3D mechanical earth model (3D MEM) were created and used to determine the complexity of the hydraulic fracture geometry. The microseismic data obtained during the hydraulic fracture simulations served to constrain the hydraulic fracture footprint.

The proposed workflow uses unconventional fracture modeling (UFM) to predict the propagation of complex hydraulic fracture networks with pre-existing natural fractures and model the stress shadow effect and the lamination effect considering different proppant placement by type within the fracture. Propped and unpropped fracture half-lengths obtained during history matching provide calibration for the UFM. Based on the calibrated model, an analysis of the current perforation efficiency was performed, which showed that almost half of the perforations do not contribute to the production. Optimization of well spacing and cluster spacing was performed on a two-well pad to account for well interference such as fracture hits, stress shadow, and depletion after 30 years of production. The recommended well spacing and completion design improved production by up to 20% per well compared to the initial development plan.

The complex approach is becoming a new norm for the successful development of unconventional reservoirs because simple analytical models cannot address well interference issues and account for heterogeneity in the rock properties. The presented workflow can be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus to help achieve maximum recovery.
Gas Lift Robbing Prevention in Dual String Completion using Production Pressure Operating Valve
Authors: Sajjad Farasdaq Muchibbus , Sastradinata Khairullah , Rahmawati Silvya Dewi , Mansur Achmad , Wirawan Alvin , Mujib Ecep
Published: October 2019

Common problem for dual string completion gas lift well is a misallocation problem called as a gas lift robbing, where the gas tends to be injected uncontrollably to one of the tubings. Consequently, both oil production of the strings drops since the injected gas does not meet the optimum allocation. To solve this, engineers need to shut in one of the strings using wireline which is time-consuming and uneconomic. Therefore, the objective of this paper is to introduce the modification of dual string gas lift design that can economically prevent gas lift robbing problem in the well during the production time.

This finding occurred in Indonesia, Offshore North West Java field, where the orifice is preferably used as the operating valve. However, Production Pressure Operating (PPO) valve is then used to replace the orifice function to overcome the problem. The methodology starts with well selection based on the possibility to perform the new design. Then, the static bottom-hole pressure test applied in each zone to obtain an appropriate pressure. Lastly, PPO valve’s Pressure Test Rack Opening (PTRO) will be designed based on the measured bottom-hole pressure to be applied to one of the selected string to prevent the gas lift robbing.

The force balance is then calculated, and the PPO valve is set to the short string with the Pressure Test Rack Opening (PTRO) 585 psig at 80°F. The oil production in the robbing well observed to increase by 45% and achieved a sustainable production after replacing its orifice with the PPO valve. Also, The PPO valve will prevent the gas robs to the selected string as it will close automatically when its tubing pressure drops bellow PTRO. Hence, the wireline activity is now unnecessary because the PPO valve will be closed automatically when the gas lift robbing occurs again.

The use of PPO valve is commonly suitable as an unloader in low availability of Casing Head Pressure (CHP) and high reservoir pressure. By this study, PPO valve has been successfully replaced orifice function with high CHP and low reservoir pressure to prevent the gas lift robbing problem effectively in Offshore North West Java field.
Holistic Digital Transformation – Key Enabler to Enhance Productivity, Flexibility and Reliability for an E&P Company
Authors: Deka Mousumi , Roychoudhury Atindra
Published: October 2019

The upstream E&P industry encompasses diverse range of activities. The core activities may be broadly classified as G&G, Drilling, Production and Transportation and non-core activities supporting efficient execution of core activities and the business as a whole may be classified as Finance, Contracts and Purchase Management, HRM and Engineering services. E&P industry is one of the earliest adopters of digital technologies in its operations to efficiently transform complex reservoirs into revenues.

Oil India Limited (OIL), the 2nd largest national E&P Company of India too adopted digital technology in its G&G activities encompassing Seismic data acquisition, processing, interpretation and logging in 1970s. It was followed by use of high end workstations for reservoir studies & modelling in 80's. Over the years, OIL deployed number of digital interventions in both core and non-core activities. However, like other E&P companies, induction of digital technology is slow in core activities like Drilling and Production. As far as non-core activities are concerned, advanced digitisation methodology adopted in the area helped OIL in enhancing efficiency and ease of data access in B2B, B2C relationship.

Crude oil and Natural Gas price volatility demands that E&P organizations to be more agile and competitive. Thus there is need of collaborative workplace with real time data analysis and efficient decision making facility. As a solution, number of intelligent IT technologies in the form of IoT, Data Analytics, Machine learning, Artificial Intelligence, Augmented Reality etc. are emerging at an affordable cost. Adopting these technologies in a holistic way integrating all core and non-core activities of an E&P industry can fulfil the need of above desired solution enhancing productivity, flexibility, reliability and RoI.

Believing "Holistic Digital Transformation" is the success mantra to become more agile and competitive, OIL has embarked in the process of implementing new digital technologies integrating all its core and non-core activities. The paper describes OIL's methodology towards holistic digital transformation.
Water Injection Optimisation for Matured Waterflood Reservoir: A Case Study for Value Creation from Improved Production Performance and Cost Savings
Authors: Md Yunos Khairil Anuar , Mansour El Harith Mohammed
Published: October 2019

This paper will highlight the study, implementation and results of water injection optimization program in a matured waterflood reservoir prior to the implementation EOR IWAG tertiary recovery. The scope included analytical understanding of current reservoir condition, reservoir simulation study for various injection proposals, historical injection facilities performance and the optimization/remediation proposal to increase WIM (Water Injection Module) uptime, and reservoir surveillance requirement to ensure the water injection optimization program meet its objectives.

Low current offtake rate in the reservoir, low WIM uptime, high cum. VRR and an imbalance in the reservoir pressure between the Eastern and Western flanks of the reservoir necessitated a study on the WIM program/schedule to optimize the injection by redistributing the injection volume between the Eastern and Western injectors and identify opportunities for cost saving through WIM shut-off. A history matched model was used to evaluate different injection scenarios. Collaboration between Subsurface and Surface Facilities Team enabled a coherent plan for periodical WIM shut-off and maintenance activities to be designed in order to deliver higher WIM uptime.

The proposals for the injection optimization program were: Apply ‘1 Month Off - 2 Months On’ Injection Cycle, starting April 2017Increase avg. water injection target to 15 -20 kbwpd as per full WIM capacityRe-balance the injection volume between Eastern and Western injectors by ratio of 3:1Maintain WIM/Injection uptime consistently above 76% during injection months

The results from the optimization exercise (May 2017 - December 2017) were encouraging and better than expected from simulation run. Production decline from producing well was successfully arrested with cum. oil gain from the period totaling approximately 18 kbbls (50 bopd annualized). The reservoir pressure in the Eastern flank was increased to reach the level similar with the Western flank. The value creation from additional production gain and cost savings of WIM shut-off was around USD 1.4 MM.

It can be safely concluded that the injection optimization plan has successfully achieved its objectives.

The novel idea and approach from this exercise was the demonstration of how a simple understanding of a reservoir and its associated surface injection performance can provide an opportunity for a quick and simple optimization plan to be implemented to improve the sweep efficiency of the injection by targeting the unswept/bypassed oil and subsequently increase the oil production from producing well(s).
History Match Process Optimizer - HMPO
Authors: Ghamdi Amell , Oluwa Jubril
Published: October 2019

This paper presents an automated method to speed-up the process of history-matching simulation models. A new tool "History Match Process Optimizer– HMPO" was developed to allow local modification of simulation model property arrays around any given well type. Deployment of this tool significantly improved the history-match process of a reservoir simulation model containing a high number of wellbores and a saving of 140 man-hours was achieved.

The tool was developed in LINUX environment and adapted to an in-house developed state-of-the-art reservoir simulator, GigaPOWERS (Dogru et al. 2008, 2009, 2011). The tool has an automated workflow that uses the model perforation file as an input to generate the property modifier file; the perforation file contains all completed wellbores along with their perforated cells. Additional input includes specifying what model property array would be modified around the wellbore (transmissibility, permeability, porosity, fluid contacts, etc.), and number of cells to be modified in 3D directions.

Application of this tool was done on a simulation model as part of the history-match process, 65% of the wells are horizontal or multilaterals. Prior to using this tool, difficulties were experienced when attempting to manually perform local history-match modification around each wellbore to mimic hydraulic fracture completion with fractures extending to several cells away from the wellbore, especially in a fine Giga-scale model with a high number of wellbores. The implementation of HMPO allows a quick generation of the modifier files with ability to repeat the process several times until an appropriate local modifier is achieved for all wellbores at the same time. This made the process of generating the modifier file 200 times faster. Hence this tool became a necessity with large complex models built with high resolution, and advanced computational resources.

The novelty of this work is to assess simulation modeling by providing an automated property-array modification around any given wellbore completion in a way that significantly reduces the duration of history- match process. "HMPO" is an internal effort to speed-up and optimize this part of history match process. Therefore, its application to other big reservoir simulation models in the company would add value, improve efficiency of the process, and enhance the quality of results obtained from history-match calibration.
A Novel Hybrid Enhanced Oil Recovery Method by Smart Water-Injection and Foam-Flooding in Carbonate Reservoirs
Authors: Hassan Anas. M. , Ayoub Mohammed , Eissa Mysara , Bruining Hans , Al-Mansour Abdullah , Al-Guraishi Abdulrahman
Published: October 2019

This contribution focuses on recovery of oil by using a newly hybrid Enhanced Oil Recovery (EOR) method, which combines smart water (i.e. ionically modified brine) and foam flooding of light oil with dissolved carbon dioxide at high pressure in carbonate reservoirs. Ionically modified brine (i.e. low salinity) has a dual improvement effect. It not only leads to more stable foam lamellae, but also helps to change the carbonate rock wettability from oil-wet to more water-wet, which has for some conditions more favorable relative permeability behavior. The mechanism for the modified permeability behavior in the presence of ionically modified brine is only partly understood. Therefore, we use the DLVO (i.e. Derjaguin, Landau, Verwey, and Overbeek) theory (i.e. which considers double layer repulsion, born repulsion, and Van der Waals attraction) and surface complexation modeling to better understand the mechanism(s) of ionically modified brine as wettability modifier and foam stabilizer. We use the PHREEQC software to obtain the equilibrium concentrations and surface potential and to study the effect of salinity and carbon dioxide gas pressure for a given choice of the surfactant (i.e. carboxylic acid R-COOH). It is conjectured that high carbon dioxide pressures have a destabilizing effect on the film, as they reduce the surface potential. A reduced surface potential leads to a decreasing electrostatic double layer repulsion and thus destabilizes the stability of the foam film, whereas low salinity leads to less screening of the surface potential and thus improves the stability of the foam film. The low-salinity flow is characterized by a high residual oil saturation and low end-point permeability for the two-phase oil-water flow. For the calcite surface an enhanced stability help to stabilize the water film on the calcite surface if the oil-water surface charge has the same sign as the surface charge on the calcite surface. Our calculations show the pH range where the sign of these charges is the same or opposite at low-salinity and high-salinity conditions. Admittedly, these calculations only show trends, but can be used to delineate optimal conditions for the use of combined Smart Water Assisted Foam (SWAF) flooding.
Analysis of Friction Reduction System during Drilling Operation at High Inclination Well on Field X
Authors: Mudhoffar Rizqiana , Lumbantobing Jerry M. , Bayuartha Pratama
Published: October 2019

Torsional vibrations (stick slip) and limited reached drilling are slowing down drilling operations and increasing drilling costs. Therefore, to mitigate these problems, the use of Friction Reduction System (FRS) is considered. FRS is a system commonly used to reduce downhole friction during drilling operations. Drilling parameter results are compared with offset well that had high stick slip.

The approach was based on qualitative research method, data processing obtained from the drilling operation of the well X. The method was performed by evaluating the use of FRS in the BHA series during the drilling operation. Such method mainly revolves around calculating some drilling parameters such as Torque, Weight on Bit (WOB), Rate of Penetration (ROP), Revolutions per Minute (RPM) and analysing the log results of the tools contained in the Rotary Steerable System (RSS) and Measurement While Drilling (MWD), as well as comparing it with offset well Y, which had high stick slip.

The result of data analysis shows that the use of FRS tool on drilling of well X is more effective and efficient compared to well Y, evidenced by drilling parameter such as WOB and Torque that are reduced by around 30%, with downhole and surface RPM being relatively constant, and supported by log results that do not show any signs of stick slip. Furthermore, the use of FRS tool is compatible with BHA component (Mud Motor / RSS / MWD / LWD) as no problems was caused by FRS on the dynamic data of drilling well X. By comparing the two wells, the use of FRS on well X proved the ability to reduce the stick slip and increase weight transfer, thus reducing the cost of drilling.

The expected result of this analysis is a reference to the use of FRS tools as a component of BHA that is placed a few feet away from the bits in accordance with its effectiveness level that can reduce the potential hazards of stick slip vibrations and expected to improve drilling efficiency in terms of time and cost.
Systematic Management for Drilling Process Improvement
Authors: Damski Carlos
Published: October 2019

Today every Oil & Gas company is talking about Digital Transformation as a new mantra, making reference to the more recent digital technologies such as IoT, Big Data, Machine learning, etc. Historically we already have seen such "transformations" in the past, such as agricultural revolution with tractors and such, the industrial "revolution" with assembly line and mass production, etc. There is nothing intrinsically new about the recent "digital revolution" and it is more like a déjà vu situation, raising similar questions and some dreadful future scenarios.

Using the basic tripod of people-process-technology, I would argue that the people are the same, regardless of the "revolution". The "technology" is just the enabler of the revolution, the same as the tractor or IoT technology. What really matters is the "process" of how people can use the technology to deliver improved results. Hence, this paper looks into the drilling business from a "process management" perspective as a means to effectively use the digital technology currently available.

Over the last 100 years, "scientific management" has been used or was used as a basis for many current process management styles. Understanding what has worked and what has failed in the past. Learning from the past, gives us a better model for the process to use the current flood of data measurements.

I would like to propose some working models for drilling continuous process improvement, a methodology and some guidelines used.