Jiang, Wei (China Natl. Offshore Oil Corp.) | Zhou, Shouwei (CNOOC China Limited Tianjin) | Liu, Liangyue (China National Offshore Oil Company, Limited -Tianjin) | Zhang, Chunyang (China Natl. Offshore Oil Corp.) | Fan, Baitao
This paper summarizes the three big challenges in the development of the oilfields in Bohai Bay: most of the reserve is heavy oil; formation is unconsolidated and lower productivity after sand control operation. Through years of research and improvement, based on serious analysis of reservoir characters and oil production performance, method of drilling and completion and production management, traditional distribution of the mesh of directional well and conventional gravel pack sand control method are changed and an alternation of sand management multilateral technology is adopted to enhance the production and oil recovery with three technology characters: one is the control of the drop of production pressure under the condition of sand management, until this technology is applied in Bohai Bay, remarkable achievement is made in the field of enhance the production and oil recovery for the development of new oil field and the reboot of the older oil field, which has been one of the key technologies to apply to a large scale and continuously improve. It has been exerting a lot of pressure and positive influence on the technology of production, drilling and completion technology, and further performance of the EOR.
Key words: Bohai Bay Oilfield development Drilling and completion technology multilateral well Sand management Enhanced oil recovery
For steam injection parameters of greater than 700 psi and 500 deg F, a high production casing failure rate is often observed. This is due to severe thermal stress condition to the production casing string. The production casing may easily be in compression hot-yield under these conditions. This can lead to high casing failure risk in the forms of excessive deformation, buckling, and collapse. This paper presents an analysis on casing and cement stresses under the stated steam injection conditions. The interaction of casing-cement-formation is considered to help understand casing and cement failure mechanisms and potential approaches to reduce casing failures in cyclic steam frac wells. The loss of cement integrity and support to production casing string may occur under steam injection condition, which attributes to casing failures in the forms of excessive deformation, buckling, and collapse.
Field surveyed temperature in a cyclic steam frac well is also presented and compared with modeled casing temperatures to show the needs of correctly modeling casing temperatures. Recent casing design practices in some Bakersfield area cyclic steam frac projects, including the successful use of high strength grade casing such as P-110, are discussed in order to reduce casing failures in the cyclic steam frac wells.
Changes of transportation materials, operating parameters or equipments of pump stations, will induce surge in oil transfer pipeline. And surge generated by accidental Shut-off fast closing valve could be more destructive, since the valve closure duration is limited, then the induced surge pressure would be much higher, so controlling surge of this kind is indispensable. Based on the characteristic method, this paper establishes a numerical calculation and simulates the pressure variation process, when fast closing valve at terminal station is accidentally shutted off in an product pipeline. Upon the upper result, further research combining the boundary condition of relief system is carried out, with the purpose of getting optimal surge control measures through relief system.
Production in most wells follows a predictable pattern dictated by the decline curve. Initially high production is quickly followed by a long, measured decline. This potentially long decline in production, together with an ever-increasing demand for energy, has resulted in many mature, low production fields. To stem the decline in production in these wells and extend the viable economic life of these assets, operators are increasingly turning to advances in technology. Technologies such as improved slimhole re-entry drilling bottomhole assemblies (BHAs), enhanced reservoir navigation systems, and improved conventional drilling techniques are successfully meeting the challenges of developing mature fields in established oil and gas basins around the world. This combination of techniques and technologies is being used in the Williston Basin to increase the recoverable reserves and improve the present economic value of each asset.
Production from the Williston Basin declined from the time of its initial discovery through the early 1990s. The introduction of horizontal re-entry drilling technologies then revitalized this region.
Targeting these thin beds typically requires extending 4½-in. laterals from existing or new vertical 7-in. cased wells. In the recent past, re-entry performance was confined by well placement restrictions, water and salt zones, and available drilling technologies. These requirements restricted the wellpath to relatively tight radius build sections. Together with the drilling difficulties associated with slimhole tubulars, these tight builds often resulted in high drag in the hole, limiting the lateral section to 3,000 to 4,000 ft due to weight transfer and drag constraints. However, in recent applications that did not suffer from such restrictions or the consequences of the water/salt formation hole instability issues, larger radius curves could be incorporated into the wellplan. This increased radius reduced drag in the well program, which together with improved motor technologies and experienced wellsite execution, allowed the 4½-in. re-entry section to achieve world record open slimhole multilaterals. The successful completion of such multilateral wells provide for over 10,000 ft of potential reservoir exposure in this thin bed.
The Williston Basin is a large, roughly circular sedimentary basin covering several hundred thousand square miles along the eastern edge of the Rocky Mountains straddling the northern U.S.A. states of western North Dakota, eastern Montana, as well as southern Saskatchewan, and Manitoba in Canada, as shown in Fig. 1. The scope of this paper will concentrate on the North Dakota portion of this basin.
Oil production began in earnest in the North Dakota Williston Basin in 1951 when Amerada Hess completed and produced its first commercial well. Drilling continued in a cyclical nature for the next 50+ years with production mainly based upon the Mississippian Madison Group formations, although some Mesozoic strata are productive (see Fig. 2). Currently, 3,300 oil wells are still producing in North Dakota. Additionally, there are over 14,000 wells existing in the North Dakota Williston Basin, having produced over 1.5 billion barrels of oil. Annual oil production peaked in 1984 at more than 52 million barrels of oil, followed by the expected and inevitable steep decline, as shown in Fig. 3.
The decline was temporarily arrested in the late 1980s with the introduction of horizontal drilling of the Bakken formation. Subsequent advances in horizontal drilling techniques and technologies allowed for further exploitation of other formations to alter the production decline again in the late 1990s and mid-2000s. Although production will probably never again reach the peaks achieved 30 years ago, the reversal is so drastic that production in North Dakota is currently on the rise (see Fig. 3).
The Birdbear (Nisku) formation oil-producing payzones are characterized by compartmentalized secondary porosity thin beds locked in deep muddy limestone and dolomite formations. The Nisku ‘A' dolomite is encased between two impermeable anhydrite beds, creating a large regional stratigraphic trap, ideally suited for horizontal drilling and subsequent viable economic development. In this particular area of the Williston Basin, formation thicknesses vary from 2 to 4 ft (0.7 to 1.2 m) when exposed with vertical wells. Traditionally, the Birdbear is relatively low on the list of most prolific oil-producing zones, ranking 10th overall in Table 1.
Guo, Xiao (The State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Du, Zhimin (The State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation) | Zhang, Yong (Southwest Petroleum University) | Wang, Li (PetroChina Southwest Oil & Gasfield Company) | Shu, Zhuangzhi (SINOPEC Inst Petr Expl & Devel)
Sulfur deposition in the formation, induced by a reduction in the solubility of the sulfur in the gas phase, may significantly reduce the inflow performance of sour gas wells and even wells have become completely plugged with sulfur in sour gas reservoir within several months. Accurate prediction and effective management of the sulfur deposition are crucial to the economic viability of sour gas reservoirs.
In this paper, the influences of gas flow rate, initial hydrogen sulfide concentration and reservoir rock permeability on sulfur deposition in the core samples from X sour gas reservoir are investigated from a laboratory and simulation perspective. Displacement experiments were conducted using the gas sample with hydrogen sulfide concentration of 19%. The gas sample were flooded through the actual carbonate core sample of permeability in the range of 0.85 to 20 millidarcy and under different flow rates of 0.82, 1.25 and 3.50 cc/min. In-situ sulfur deposited was measured using Scanning Electron Microscope (SEM) to provide the amount of sulfur deposited along the core samples. In addition, a three-dimensional, multi-component model was developed to evaluate the influences of gas flow rate, initial hydrogen sulfide concentration and reservoir rock permeability on sulfur deposition.
The results indicated that the higher of gas flow rate can reduce the deposition of sulfur, while the higher of hydrogen sulfide concentration have a severe effect on sulfur deposition in sour gas reservoir. In addition, the depositional rate is accelerated rapidly as the rock permeability decreases. This work can help predict exactly the permeability damage rate as a function of flow rate, or initial rock permeability and production performance during the development of sour gas reservoir.
Sponsored by CNPC Innovation Fund and also funded by NSFC (No. 50474039) and SCST ( No. 04JY029-121).
Elemental sulfur is often present in appreciable quantities in sour gas at reservoir pressure and temperature conditions[1-2]. On the one hand, reduction of pressure and temperature generally reduces the solubility of sulfur in sour gas. Once the reservoir fluid has reached a sulfur-saturated state, further reductions in pressure and temperature will cause sulfur to deposit. On the other hand, the sulfur in the gas phase also reacts to form a hydrogen polysulfide species[3-5]. Since high pressure and temperatures favor polysulfide formation, deposition of elemental sulfur occurs when changes in pressure and temperature alter the decomposition of polysulfide to elemental sulfur and H2S. Sulfur deposition in the formation, the vicinity of the wellbore and the production line, may significantly reduce the inflow performance of sour gas wells and even wells have become completely plugged with sulfur in sour gas reservoir within several months. Accurate prediction and effective management of the sulfur deposition are crucial to the economic viability of sour gas reservoirs.
Li, Lin (Petrofina S.A.#3 Daqing Oilfield Co.Ltd.) | Ji, Bingyu (Daqing Oil Field Co. Ltd. of PetroChina) | Cui, Baowen (Daqing Oil Field Co. Ltd. of PetroChina) | Zhou, Xisheng (Daqing Oil Field Co. Ltd. of PetroChina) | Li, Min Li (Daqing Oil Field Co. Ltd. of PetroChina) | Zhang, Hengfa (Daqing Oil Field Co. Ltd. of PetroChina) | Luo, Qing (Daqing Oil Field Co. Ltd. of PetroChina) | Zhang, Xingping (Landmark Beijing) | Zhang, Biqing
In view of the features of the remaining oil after a period of production since secondary infilling adjustment of water flooding development oil field, that is, low quality, unbalanced planar distribution and high vertical dispersal, study on tertiary infilling adjustment optimized well spacing has been carried out . The study has solved the problems of reasonable well spacing density, injector-producer distance, injection-production system, how to locate wells near old injector array, and how to adjust and integrate with the original well pattern, with the tertiary recovery well pattern and with the injection-production system. The overall strategy and optimized well spacing method for tertiary infilling adjustment have been brought forward consisting of reasonable well location region division ?balanced well spacing ?well by well scanning ?local adjustment ?step by step implementation. The study has a wide guidance for the tertiary infilling adjustment of other blocks to find practical, feasible and effective approaches.
1. Development Overview
Development Area is located in Daqing placanticline with an oil bearing area of 20.2km2. The block was brought into development in 1965 as major reservoirs in Sartu and Putaohua oilfields. Since then two times of infilling adjustment had been conducted aiming at Pu 2, Gao Middle, low permeability layers and Sartu thin and poor reservoirs. 250×300m inverted nine spots area injection pattern is adopted without exception. After secondary infilling, the well spacing density reached 30.25 wells/km2.
According to the refined geologic anatomy result, the remaining adjustable sandstone thickness after secondary infilling adjustment in East of North 3 Block is predicted as 12.44m and the effective thickness is 1.88m. Tertiary infilling adjustment has certain material base, but the remaining oil planar distribution unbalance and vertical high dispersivity have determined the hardness of production potential development. Therefore, the approach should be started from technical and economical indexes to optimize well spacing with a possible better adjustment effect.
2. Study on Tertiary Infilling Adjustment Optimized Well Spacing
2.1 Tertiary infilling adjustment adopts five spots area water injection pattern, with well spacing of 200-250m and reasonable well density lower than 50 wells/km2
2.1.1 Injection-Production System Screening
Numerical simulation is applied to compare the development effects of five spots, four spots, and inverted nine spots injection-production systems in the thin and poor oil layers and surface layers. The result shows that the average water flooding control degree of five spots area well pattern is 8-10% high than other well patterns. At the same water cut, the recovery degree is higher than other injection-production systems. Therefore, the injection-production system of tertiary infilling adjustment should select five spots pattern.
2.1.2 Reasonable Well Spacing Determination
The inspection well data statistics show that the floodout proportion of surface reservoir gradually decreases with the increase of the distance between inspection well and water injection well. The distance limit of significant floodout status variance is 250m. When the injection-production well spacing is larger than 250m, the floodout proportion is only about 20%. That means the thin and poor oil layers have a poor production if the well spacing is too large. On the other hand, the development study on the surface reservoirs of other blocks in the recent years also indicates that too small injection-production well spacing can cause unfavorable rapid water cut increase. Considering the factors of the above two aspects, the reasonable injection-production well spacing for thin and poor oil layer and surface layer effective development should be 200-250m.
Gas Charged Accumulators are widely used in Drilling operations. These accumulators are not efficient at all in Deep waters, and there are not many alternatives for them. This paper looks into possible alternatives for Gas Charged Accumulators in Deep Waters.
Supplying enough volume of pressurized hydraulic fluid to operate the BOPs for emergency situations is essential for Deep Water Drilling. This requires storing the pressurized hydraulic fluid in accumulators. A problem may arise when the wellhead is at water depth of more than 3500 ft. In deep water drilling, the accumulators are placed on the subsea BOP stack to reduce hydraulic response times and provide a hydraulic power supply in case of interruption of surface communication. Hydraulic fluid capacity of an accumulator may drop to 15% of its capacity on the surface and even less, depending on the water depth. The reason for this is that the nitrogen gas does not behave like an ideal gas as we go to very deep water, due to high hydrostatic pressure at that water depth.
The possibility of the use of springs and heavy weights as possible replacements for nitrogen in the structure of accumulators will be discussed in this paper. High hydrostatic pressure of deepwater will not affect the functionality of these mechanical accumulators.
Transferring bank of accumulators to the surface and connecting them to the BOP with properly sized and rigid pipes can decrease response time to an acceptable level to satisfy regulations and standards. This idea can be considered as an alternative solution too.
We have to include the hydrostatic pressure of water in the usable fluid calculation. A low pressure tank located on the sea-floor can dismiss the negative effect of high hydrostatic pressure of seawater. This alternative idea is also discussed.
Using a column of high density fluid as the accumulator system is another alternative method that is presented in this paper and should be investigated further for such application.
The East Kalimantan Gas Pipeline Network extends from the south part of the Mahakam Delta transporting the natural gas from East Kalimantan PSCs (VICO Indonesia, TOTAL Indonesie, and Chevron Indonesia Company) to the largest LNG complex in the world - 8 trains at PT Badak NGL and also to the Fertilizer/Industrial Plants in Bontang. Normal daily production rates of East Kalimantan PSCs are 3,300 - 3,400 MMscfd with a maximum of 3,700 MMscfd. The majority of the East Kalimantan Gas Supply to the Customers are transported through 56 km 4 (four) main pipelines i.e. 2x36?? and 2x42??, known as Badak-Bontang Pipelines, operating in parallel, from the common Gas Export Manifold at Badak Field.
Daily operations of the 4 pipelines have to deal with a number of constantly changing parameter i.e. production rates from the producers that will impact to the change of gas composition. Because of the gas composition, temperature and pressure change along the pipelines, a certain fraction of the gas is naturally converted into liquid in the pipelines. As most of liquids are carried through a system of parallel pipelines, some of them will stay in the bottom section of pipelines which is referred as Liquid Hold Up (LHU). This LHU, if become excessive, eventually will restrict gas flow and increase backpressure to the upstream production facilities which could further reduce the total gas delivery from the production plants/platforms. Identification of which pipeline having LHU problem is not easy since the pipelines share the common header at both ends. VICO Indonesia as Operator of East Kalimantan Pipeline Network and Coordinator of East Kalimantan Gas Operation therefore is challenged to manage the pipeline operations under conditions of fluctuating gas supply in order to optimize gas production from the producers.
Several procedures and technologies have been implemented. When first introduced, Switching Guideline of Badak-Bontang Pipelines was derived from semi empirical analysis with steady state process simulation and limited field data. This guideline is designed to provide criteria for switching operation between Pipelines operating modes to minimize LHU. Over period of time, the guideline has gone through a couple of revisions, including the introduction of term ‘Operating Green Box' (the name given to operating parameters of pipelines in low LHU condition) as supported operational data from experiences increases. Pigging guideline was also developed to determine at what kind of flow and pressure conditions in Badak-Bontang Pipelines that are considered adequate for pigging operation. The purpose is to avoid getting a pig stuck in a pipeline.
Last improvements in Badak-Bontang Pipeline Operations include the development of more efficient and effective sweeping procedure to reduce high LHU in one of four main pipelines by Pipelines segregation at Badak Export Manifold and the utilization of Dynamic Process Simulation to better predict and anticipate fluid dynamic behavior inside the Pipeline. The installations of Ultrasonic Flow Meter at individual pipeline and Telemetry system in Pipeline network help Pipeline Operations to quickly identify which pipeline having LHU problem. With those continuous improvements, VICO Indonesia has been able to successfully manage LHU problems at the complex gas pipeline network in East Kalimantan.
This paper provides a case history of the experience in managing the complex pipelines operations in East Kalimantan and shows the solution to solve the liquid hold problem due to changing of operating conditions.
The Duri field in Sumatra, Indonesia shown in Figure 1 operated by Chevron Pacific Indonesia (CPI) is one of the largest steam flood operations in the world. Producing heavy oil (API gravity˜25) from an essentially unconsolidated reservoir with a depth that ranges from 300 - 700 feet using steam injection @ 300 - 400°F poses a unique challenge in designing an effective yet economic completion. One of the biggest problems associated with the production of the crude oil in this environment is the production of solids, i.e., sand. It is reported that greater than 1,000,000 lbs of sand per day are produced from the field. In addition to the cost of the re-completions, problems associated with disposing of this amount of sand; and the effect the produced solids have on the facilities such as stabilization of emulsions is a large cost to operations.
A program was initiated in 2002 to evaluate the effectiveness of the completions in the Duri field. This effort involved evaluated field data such as the frequency and type of workovers, the amount and size of produced solids, the nature and number of failed liners, and the frequency of stuck pumps to better understand the efficiency of the sand control completions. Local sand control gravel used in the completions was evaluated for steam dissolution and adherence to API gravel pack sand standards. An audit of the primary sand control screen manufacturer was also conducted to evaluate the quality of the sand control screens used in the completions. In addition, on-site inspections of the operational aspects of the completions were done. The results of the program showed the completion designs, and sand control screens were up to industry standards. However, several operational aspects were identified as opportunities for improvement. The results of the program are presented, and items for improvement of the completion for thermal wells in the Duri field are discussed in this paper.
Understanding the Produced Solids
The origin and cause of solids production was not well understood. A field wide effort was initiated to sample produced fluids and solids from wells, test stations and gathering stations. Bailed sands from well services and workovers were also collected for analysis. The analysis objective was to understand size, nature and amount of gathered solids at surface.
Several particle size analyses were done to understand the particle size distribution on both core and produced/gathered solids in order to get a better picture of the produced solids origin. Figure 2 shows a laser particle size distribution (LPSA) of a typical formation in the Duri field. Figures 3 & 4 show the histograms of typical produced and bailed samples from wells in the field.
Inspection of Figures 3 & 4 reveals that most of the solids produced to the surface are consistently the very small particles; whereas, the bailed samples were mostly the larger particles. This observation was not unexpected. Some of the larger material analyzed was gravel pack sand which indicated that the sand control placed in the well was compromised to some level.
Origin of Produced Solids
A major concern for the project was to understand the source of the "fine?? solids produced from the wellbore. It was not clear if the production of the fines was just characteristic of the formation or as a result of some type of interaction of the steam and the formation. Typical mineralogy percentages of the Duri formation are given in Table 1.
Several tests were conducted which consisted of initially flowing simulated formation brine through a core sample, and then stepwise decreasing the salinity. The decrease in salinity simulates the decreasing salinity of the water in the formation as a result of the injecting steam to stimulate the oil.
The main pay of Guantao Formation in Gudao Field is a large-scale thick positive-rhythm channel sand oil layer. At the extra high water-cut stage, the thick oil layer is waterflooded seriously, but the top remaining oil is still enrichment due to influence of reservoir heterogeneity. The research shows that the development effectiveness of tapping the potential with vertical well is bad and the economic benefit is low . If horizontal well is used, the producing degree and the recovery of the remaining reserve can be improved effectively. Among various factors of affecting development effectiveness of horizontal well, the influence of intraformational bed development is much more important. The development of intraformational bed and its control on remaining oil distribution should be understood first, then the technology policy research of tapping the potential with horizontal well was conducted in order to ensure the good development effectiveness with horizontal well. In this paper, the remaining oil distribution features under the different developmental conditions of intraformational bed are expounded in detail, the intraformational bed was divided into two kinds, developed and undeveloped; according to its developmental conditions, the technology policies of horizontal well were studied respectively, and the commensurate design criteria of horizontal well was proposed. The application of the achievements in tapping the potential of remaining oil in thick positive-rhythm oil layer during the extra-high water cut period has achieved preferable effectiveness, which provides reference for that in the same type of reservoir.
Extra-high water cut reservoir, Thick positive rhythm oil layer, Intraformational bed, Remaining oil, Horizontal well
Gudao oilfield is one of four uncompartmentalized oilfields in Shengli petroleum province, characterized by fluvial reservoir which is the primary type of reservoirs found in China . At present, Gudao oilfield has been developed for more than 30 years and is at the extra high water cut stage, the distribution of remaining oil is very complicated due to the influence of reservoir heterogeneity and long-term waterflooding, and the challenge is how to tapping the potential of remaining oil at extra-high water cut stage. The main pay of Guantao Formation in Gudao Field is a large-scale thick positive-rhythm channel sand oil layer. At the extra-high water cut stage, the thick oil layer is waterflooded seriously, but the top remaining oil is still enrichment due to influence of reservoir heterogeneity. The research shows the problem existing in the thick positive rhythm sand oil layer could be resolved at extra high water cut stage by horizontal well can be solved, the potential of low permeability interval can be tapped and the producing reserves and the oil recovery can be improved. The development condition of intraformational bed is the key of many factors influencing the development effectiveness of horizontal well because the distribution of remaining oil is significantly influenced by intraformational bed during extra-high water cut period. Based on the development condition of intraformational bed in the thick positive rhythm oil layer and its influence on the distribution of remaining oil , the technology polices of horizontal well in tapping the potential had been worked out. Therefore the advantage of horizontal well can be brought into play.