Nagar, Ankesh (Cairn Oil & Gas – Vedanta Limited) | Dangwal, Gaurav (Cairn Oil & Gas – Vedanta Limited) | Maniar, Chintan (Cairn Oil & Gas – Vedanta Limited) | Bhad, Nitin (Cairn Oil & Gas – Vedanta Limited) | Goyal, Ishank (Cairn Oil & Gas – Vedanta Limited) | Pandey, Nimish (Cairn Oil & Gas – Vedanta Limited) | Parashar, Arunabh (Cairn Oil & Gas – Vedanta Limited) | Tiwari, Shobhit (Cairn Oil & Gas – Vedanta Limited)
The Mangala, Aishwaya & Bhagyam (MBA) fields are the largest discovered group of oil fields in Barmer Basin, Rajasthan, India. The fields contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. The fields have undergone pattern as well as peripheral water injection. In order to overcome adverse mobility ratio and improve sweep efficiency thereby increasing oil recovery, chemical EOR has been evaluated for implementation in these fields. The potential benefits from chemical enhanced oil recovery (EOR) had been recognized from early in the field development. Polymer flooding was identified for early implementation, which would be followed by stage wise implementation of Alkaline-Surfactant-Polymer (ASP) injection in fields like Mangala. Since the commencement of polymer injection, the Mangala field polymer injectors have displayed multiple injectivity issues. In addition, the Aishwarya and Bhagyam fields are dealing with low Void Replacement Ratios (VRR) for their ongoing water injection, which if not rectified could adversely affect recovery. While various types of injector stimulations are being used, injectivity increases are short lived. A new technique termed as ‘Sand Scouring’ has been successfully applied resuting in sustainable injectivity gains.
The technique involves pumping creating a small fracture with a pad injected above fracturing pressure and then scouring the fracture face with low concentration 20/40 sand slugs in range of 0.5 to 1 PPA 20/40. The treatments are pumped at the highest achievable rates with the available pumping equipment within the completion pressure limitations. Based upon the available tankage, the scheduled is designed such that pumping of a fixed volume of sand stage, a quick shut-down allows for mixing the next stage of slurry. The pumping schedule and a ‘scouring’ intent is deliberately designed to avoid requirement of fracturing equipment, related cleanout equipment and resulting costs. The challenge of conformance is addressed by designing the pumping schedule to incorporate stages of particulate diverters and validated using pre and post injection logging surveys. .
Sand scouring jobs in 16 wells have been conducted across Mangala, Bhagyam & Aishwarya injectors. Out of thesewells, 9 wells had zero injectivity while the other 7 required both injectivity and conformance improvement. Most of the treated wells resulted in multifold improvement of injectivity as compared to their prior injection parameters. Sand scouring resulted in sustained injection performance when compared with prior conventional methods of stimulation. Injectivity improvements from sand scouring lasted for an average of 3 months days as compared to 14 days for the conventional stimulations. Sand scouring evolution, design, results and plans for future improvement are all discussed in this paper.
Wang, Gang (China University of Petroleum-Beijing) | Fan, Honghai (China University of Petroleum-Beijing) | Zhang, Wei (CNPC Engineering Technology R&D Company Limited) | Yang, Yang (China University of Petroleum-Beijing) | Han, Zili (CNPC Bohai Drilling Engineering Company Ltd.) | Wu, Hongxuan (CNPC Chuanqing Drilling Engineering Company Ltd.) | Li, Wanjun (CNPC Engineering Technology R&D Company Limited) | Li, Jiaying (CNPC Engineering Technology R&D Company Limited) | Zhou, Tuo (CNPC Engineering Technology R&D Company Limited) | Zhou, Haiqiu (CNPC Engineering Technology R&D Company Limited) | Liu, Jitong (CNPC Engineering Technology R&D Company Limited)
M15 well contains complex intervals, where anticlinal structures developed from faults make long mudstone barriers full of cracks, which makes it hard to predict pore pressure. Loss is one of the most serious problems during drilling and cementing, while blow out accidents happen sometimes. Previous casing programs hardly adjust to all complex intervals and conventional LCMs (loss control materials) play few roles. As a result, designated targets used to be rarely reached.
It is proved that low pressure intervals shall be isolated firmly and complex intervals as well as reservoirs should be developed in independent intervals, thus casing programs have been modified. 188 lab tests were finalized, including 180°C hot rolling, anti-contamination test, lubricity test and inhibition experiments, in order to develop a kind of organic salt mud system that has premium inhibition, plugging, lubricating, heat & salt resistance properties. Precise MPD (managed pressure drilling) techniques are recommended to achieve near-balance drilling operation, solving borehole instability problems to some extent.
In the second interval the organic salt mud system is applied, while logging and casing running may be accomplished in one time. Besides, strings can be tripped out smoothly and high pressure brine productive zones are drilled safely. φ339.7mm casing joints are set at the depth of 3848m in the second interval and φ244.5mm casing joints are set at the depth of 5177m in the third interval, in order that deeper complex formation may be developed in a separate casing interval in which precise MPD is applied with LCMs while drilling and compound plugging agents. Therefore, downhole pressure is precisely controlled and large cracks are plugged statically on 28 occasions. Designated targets have been all reached and 20 oil & gas productive layers have been developed.
Downhole complexities arising from loss and blowout have been solved in M15, where φ339.7mm casing was set at the deepest interval in CNPC overseas operation history, making a new record of safe drilling operation, borehole quality and cementing quality. More oil and gas productive zones have been discovered and all designated targets have been achieved. New drilling experience got from M15 has significant meanings in the development of similar blocks.
US unconventional resource production has developed tremendously in the past decade. Currently, the unconventional operators are trying many strategies such as refracturing, infill drillings and well spacing optimization to improve recovery factor of primary production. They are also employing big data and machine learning to explore the existed production data and geology information to screen the sweet spot from geology point of view. However, current recovery factor of most unconventional reservoirs is still very low (4~10%). A quick production rate decline pushes US operator to pursue gas EOR for unconventional reservoirs, lifting the ultimate recovery factor to another higher level. The goal of this work is to improve oil recovery by implementing gas Huff and Puff process and optimizing injection pattern for one of the US major tight oil reservoirs - Eagle Ford basin. Gas diffusion is regarded as critical for gas Huff and Puff process of tight oil reservoirs. Utilizing the dual permeability model, gas diffusion effect is systematically analyzed and compared with the widely used single porosity model to justify its importance. Transport in natural fractures is proved to be dominated recovery mechanism using dual permeability model. Uncertainty studies about reservoir heterogeneity and nature fracture permeability are performed to understand their influences on well productivity and gas EOR effectiveness. Moreover, three alternative gas injectant compositions including rich gas, lean gas and nitrogen are investigated in gas Huff and Puff processes for Eagle Ford tight oil fractured reservoir. The brief economic evaluation of Huff and Puff project is conducted for black oil region of the Eagle Ford basin.
One of the considerations in hydraulic fracturing treatment optimization in unconventional (shale/tight/CBM) reservoirs is creating fracture complexity through reducing or possibly eliminating or neutralizing the in-situ stress anisotropy (differential stress) to enhance hydraulic fracture conductivity and connectivity by activating planes of weakness (natural fractures, fissures, faults, cleats, etc.) within the formation in order to create secondary or branch fractures (induced stress-relief fractures) and connect them to the main bi-wing hydraulic fractures. However, actual field experience has shown that some reservoirs under certain treatment designs exhibit excessive fracture complexity due to excessive induced stresses or stress shadowing that can result in pressureout or screenout, and thus, poor well completion and productivity performance. Therefore, it is crucial to identify the reservoir candidates and treatment strategies that are suitable for enhancing fracture complexity to avoid fracturing treatment scenarios that will have an adverse effect on the well productivity.
In this work, a three-dimensional hydraulic fracture extension simulator is coupled with a reservoir production simulator to screen for the reservoir candidates and fracturing treatment scenarios that can lead to enhancing fracture complexity, conductivity, and connectivity and positive well production performance. Furthermore, scenarios are identified under which excessive fracture complexity (due to excessive induced stresses or stress shadowing) results in poor well completion performance.
The results indicate that fracture complexity can be enhanced under the following treatment scenarios: (1) low-viscosity slickwater with smaller proppant sizes under high treatment rates, (2) hybrid fracture treatment (low-viscosity slickwater containing smaller proppants and low proppant concentrations with high treatment rates followed by viscous treatment fluids containing larger proppants and higher proppant concentrations), (3) simultaneous fracturing of multiple intervals at close spacing, and, (4) out-of-sequence pinpoint fracturing (fracturing Stage 1 and then Stage 3 followed by placing Stage 2 between the previously fractured Stages 1 and 3). It is also revealed that the success of each of the above treatment scenarios is very sensitive to rock brittleness (combination of Young's modulus and Poisson's ratio), magnitude of stress anisotropy, matrix permeability, process zone stress/net extension pressure, fracture gradients, and treatment fluid viscosity and rate. Additionally, excessive fracture complexity, which impedes fracture growth due to pressure out and screenout, can be mitigated by reducing treatment rate and pressure, increasing treatment fluid viscosity, and using small particulates, such as 100-mesh proppant.
This work is the first attempt in comparative evaluation of the impact of creating fracture complexity under a variety of operationally-feasible treatment scenarios applied to a wide range of reservoir and rock geomechanical properties. It shows that wells with certain combinations of Young's modulus, Poisson's ratio, stress anisotropy, and fracture gradients are not suitable candidates for creating complexity in the hydraulic fractures system.
Jordan, Myles (Nalco Champion, An Ecolab Company) | Temple, Erin (Nalco Champion, An Ecolab Company) | Sham, Anita (Nalco Champion, An Ecolab Company) | Williams, Helen (Nalco Champion, An Ecolab Company) | McCallum, Catriona (Nalco Champion, An Ecolab Company)
Inorganic scale control of sulphate and carbonate scales with polymer, phosphonate and phosphate ester scale inhibitors is well established within the oilfield service industry. The environments in which these chemical work best have been published such as vinyl sulphonates are known to be very effective for sulphate scale control in low temperatures whereas phosphonates are much less effective under these same conditions but improve at higher temperatures. What is less well understood is the potential for synergistic interaction with blends of polymers/phosphonates/phosphate esters to give reduced treatment rates, lower chemical discharge volumes and potentially lower treatment cost.
In this paper evaluation of two North Sea produced waters will be outlined. Both produced brines have a high barium sulphate scale tendency but differ in the temperature at which the fluids arrive and depart the topside process one case with a temperature of 20C and the other at 90C. Static bottle test data will be presented to evaluate the crystal growth performance of single scale inhibitors and the improvements observed when blends of these same inhibitors are applied. Select dynamic tube blocking tests data to evaluate nucleation inhibition will also be presented so that mechanism of inhibition for the blended chemicals can clearly be highlighted.
The generic inhibitor evaluated included vinyl sulphonates co polymer, phosphate esters, poly aspartic acid. In the lower temperature environment, it was observed that a vinyl sulphonate/phosphate ester blend was more effective than either of the components by themselves. Poly aspartic acid blende with phosphate ester also give a synergistic interaction but the performance of this chemical required higher treatment rates than the vinyl sulphonate co polymer blend. At higher temperature the overall treatment rates were reduced as the sulphate scale saturation values were reduced and the synergistic effects of the polymers and phosphate ester blends were evident.
As well as classic static bottle tests performance tests were carried out in the presence of reservoir solids with stirring to further understand if the interaction of the generic chemicals within the blends with suspended solids would reduce the observed performance in the solids free test solutions.
The current regulatory challenges with REACH mean that the methods outlined in this study offer the potential to reduce chemical treatment rate, cost and environmental impact by evaluating the synergistic interaction of the current range of commercially available scale inhibitors so cutting out the very high registration costs/ time delays to the market associated with new molecule development.
We suggest two new thermodynamic models for the adsorption of ions to the brine/carbonate and brine/crude oil interface. We calibrate the model parameters to the ionic adsorption and zeta potential data. We then investigate the effect of the rock and oil surface charges on the dissolution, wettability alteration, and mechanical properties of the carbonates in the context of modified-salinity water flooding in the North Sea chalk reservoirs.
We modify a charge-distribution multi-site complexation (CD-MUSIC) model and optimize its parameters by fitting the model to a large data set of calcite surface zeta potential in presence of different brine compositions. We also modify and optimize a diffuse layer model for the oil/brine interface. We then use the optimized surface complexation models with a finite-volume solver to model the two phase reactive transport of oil and brine in a chalk reservoir, including the impact of dissolution, polar-group adsorption, and compaction on the relative permeability of chalk to water and oil. We compare the simulation results with the published experimental data.
Sokhanvarian, Khatere (Sasol Performance Chemicals) | Stanciu, Cornell (Sasol Performance Chemicals) | Fernandez, Jorge M. (Sasol Performance Chemicals) | Ibrahim, Ahmed (Texas A&M University) | Nasr-El-Din, Hisham A. (Texas A&M University)
Matrix acidizing is used for permeability and productivity enhancement purposes in oil and gas wells. Hydrochloric acid has been always a first choice due to so many advantages that it can offer. However, HCl in high pressure/high-temperature (HP/HT) wells is a concern because of its high reactivity resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. There are several alternatives to HCl, among them emulsified acid is a favorable choice due to inherent corrosion inhibition, deeper penetration into the reservoir, less asphaltene/sludge problems, and better acid distribution due to its higher viscosity. Furthermore, the success of the latter system is dependent upon the stability of the emulsion especially at high temperatures. The emulsified acid must be stable until it is properly placed and it also should be compatible with other additives in an acidizing package. This study presents the development of a stable emulsified acid at 300°F through investigating some novel aliphatic non-ionic surfactants.
This paper introduces new non-aromatic non-ionic surfactant to form an emulsified acid for HP/HT wells where the conventional acidizing systems face some shortcomings. The type and quality of the emulsified acid was assessed through conductivity measurements and drop test. Thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. Lumisizer and Turbiscan were used to determine the stability and average particle size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 200°F as a function of shear rates (0.1-1000 s-1). The microscopy study was used to examine the shape and distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes. Inductively Coupled Plasma (ICP) and Computed Tomography (CT) scan were used to determine dissolved cations and wormhole propagation, respectively.
Superior stimulation results with low pore volume of acid to breakthrough were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branch wormholes resulted from some of the treatments using conventional emulsified acid systems. The results showed that a non-ionic surfactant with a right chemistry such as suitable hydrophobe chain length and structure can form a stable emulsified acid.
This study will assist in creating a stable emulsified acid system through introducing the new and effective aliphatic non-ionic surfactants, which lead to deeper penetration of acid with low pore volume to breakthrough. This new emulsified acid system efficiently stimulates HP/HT carbonate reservoirs.
The impact of suspended solids and dynamic conditions on sulphate scale control is well-known. Previous work examined the effect of suspended solids, along with static and turbulent conditions, on one scale inhibitor (Vs-Co). This study has focused on the challenges experienced by an operator of a chalk reservoir field, with a significant amount of carbonate solids in the system, and a high sulphate scale risk due to high barium concentration, injection seawater breakthrough, and cool topside process conditions (20°C). The initial laboratory evaluation showed that the minimum inhibitor concentration (MIC) observed increased from 50ppm to 250ppm after 24 hours (>80% efficiency) under these conditions.
A further study investigated whether a reduction in MIC could be achieved with different chemistry. Various chemicals were screened in conventional static jar tests and in stirred tests to induce turbulence incorporating mixed solids. The results showed that many of the conventional scale inhibitor chemistries, working by nucleation inhibition and crystal growth retardation, could not cope with the severe scaling conditions and were less efficient than the incumbent. However, a "novel" scale inhibitor formulation was shown to work more effectively and resulted in a significantly lower MIC than the incumbent.
Under sulphate scaling conditions (80:20 FW:SW), VS-Co recorded an MIC of 250ppm which was reduced to ≤100ppm with the novel chemical. This resulted in the opportunity for the operator to reduce their chemical dose rate and logistical costs.
This novel chemical works by a combination of nucleation inhibition and crystal growth retardation. As a result of this inhibition mechanism, other operators experiencing similar harsh sulphate scaling conditions could achieve a lower treat rate in high suspended solid loaded systems.
Yu, Haiyang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Chen, Zhewei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Yang, Zhonglin (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Cheng, Shiqing (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | He, Youan (Research Institute of Exploration and Development, Petro China Changqing Oilfield Company) | Xian, Bo (Development Department, Tarim Oilfield Company, PetroChina)
Poor energy supplement and low hydrocarbon recovery are the two main shortcomings for water or gas injection in tight oil reservoir development. Horizontal well flooding can improve oil recovery and sweep efficiency of water flooding. However, the economic benefits need to be considered for long horizonal well injection. Based on a case of Changqing Oil filed, this paper presents a novel development approach, Allied In-Situ Injection and Production (AIIP), for fractured horizontal wells to increase hydrocarbon recovery, and explores its feasibility with simulation work, compared with traditional water flooding method. The impact for the existence of natural fractures in tight oil reservoir is also studied in this work. Although requiring costly special equipment, a series of simulations prove that AIIP is a more reliable and efficient approach to increase the performance of fractured horizontal wells compared to conventional methods, oil recovery and oil rate were improved significantly after AIIP was conducted. Water injectivity increased sharply than traditional water flooding with a lower injection pressure. The existence of natural fracture in tight oil formation improved the water flow inside the formation, leading better sweep efficiency and higher oil recovery factor. However, water cut in producers increased faster in natural facture enriched model than that of basic model. Thereforem it is essential to evaluate the performance of AIIP process before application.
Liu, Hongtao (PetroChina Tarim Oilfield Company) | Cao, Lihu (PetroChina Tarim Oilfield Company) | Xie, Junfeng (PetroChina Tarim Oilfield Company) | Yang, Xiangtong (CNPC Engineering Technology R&D Company Limited) | Zeng, Nu (PetroChina Tarim Oilfield Company) | Zhang, Xuesong (PetroChina Tarim Oilfield Company) | Chen, Fei (PetroChina Tarim Oilfield Company)
There is abundant natural gas in Kuqa foreland area of Tarim basin, the reservoir has characteristics of ultra depth(6500m-8000m), high pressure(115MPa-140MPa), high temperature(170°C-190°C) and complex corrosive medium, which bring well integrity high challenge. There are 52 production wells in the Kuqa foreland basin in 2012. The 16 wells of these production wells exist sustained casing pressure(SCP). The SCP wells caused by the tubing string failure is 61%.
Since 2012, in order to build safe well barrier and achieve scientific production management, consider all important periods of drilling, well testing, well completion and production in well full life cycle. the design methods of the four main well barrier components(casing string, cement, tubing string, well head) are optimized. A set of technology for well barrier quality control, well maintenance and well production management is formed. Finally, the key technology of full life cycle well integrity for ultra depth, HPHT gas well is formed.
In view of the large angle of bedding, well deviation controlled difficultly, and coexistence of high pressure saline aquifer and week bed in one open hole section which lead to serious casing wear and poor cement stone, the vertical well drilling technology, the collapse resistance casing design methods, the casing wear preventing measures, negative pressure test method and high temperature, high density cementing technology are completed. These technologies improve the safety of casing string and the quality of cement. Considering the extreme working conditions(the partial pressure of CO2 is beyond 2MPa, The content of chlorine is about 80000mg/L, acid job, 136MPa pump pressure in well head)of tubing string, material selection method, triaxial stress analysis method, quality control technology for tubing string is optimized. The failure ratio of tubing string reduced from 50% in 2013 to zero in 2017. Referencing API RP 90-2 and IOS16530-2, a special calculation method for annulus pressure management is formed, which include minimum operation pressure and maximum allowable pressure for different annulus. Then a risk assessment system is established. The SCP wells is controlled less than 22% in the condition of increasing number of high pressure gas wells.
Based on the research introduced above, China's first set of well integrity specification series is completed. The integrity specification series include the well integrity guide, the well integrity design and the well integrity management for high temperature high pressure and high sulfur gas. These results effectively support safty in production for high pressure gas field in Tarim basin, and will promote the well integrity level in the same kind of oilfield.