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Search productivity: production test
Large-Scale Laboratory Sand Production Test
Kooijman, A.P. (Koninklijke/Shell E and P Laboratorium) | Halleck, P.M. (Terra Tek Inc.) | de Bree, Philippus (Koninklijke/Shell E and P Laboratorium) | Veeken, C.A.M. (Koninklijke/Shell E and P Laboratorium) | Kenter, C.J. (Koninklijke/Shell E and P Laboratorium)
...Society of Petroleum Engineers SPE 24798 Large-Scale Laboratory Sand Production Test A.P. Kooijman, KoninklijkeIShell E&P Laboratorium; P.M. Halleck,* Terra Tek Inc.; and Philippus de...and interpretation conceptual, analytical and numerical models for of a large-scale laboratory sand production test. In sand ...production prediction have been developed, the experiment, a real well with multiple perforations see e.g. [2-...
...2 LARGE-SCALE LABORTORY SAND PRODUCTION TEST SPE 24798 between small-scale laboratory tests and field between the horizontal and vertical pressu...re was observations by carrying out a large-scale sand kept at a prescribed value, which could be production test on an artificial well in the laboratory controlled by manually following an XY plot of the under re...alistic, controlled conditions. required stress ratio. During the test flow rate, rock stresses and pore pressures were monitored ...
...nds. and cement was poured into the wellbore. The cement composition deviated slightly from what is PRODUCTION FROM THE LABORATORY WELL used in the field. Some additives had to be omitted, because they would op...erate as retarders at the Test development relatively low temperatures in the laboratory. The intended ...test program is summarized in The 3" (7.63 cm) aluminum casing was pushed into Table 3. The main objecti...
Abstract This paper describes the results and interpretation of a large-scale laboratory sand production test. In the experiment, a real well with multiple perforations was simulated, using an outcrop rock selected to represent core material from a specific field. The objective of the experiment, which was the first of its kind, was to investigate the influence of both effective stress increase and drawdown on sand production behavior, taking into account the influence of the presence of casing and cement and of perforating. An additional objective of the test was to investigate the influence of a water cut on the sand produced. The laboratory well behaved very realistically, in terms of both oil and sand production. Introduction Reliable predictions of sand production potential are required to make realistic sand production management and contingency planning possible. Unnecessary application of sand exclusion measures results in increased completion costs and considerable loss of well productivities. Further, sand prediction may assist in selecting the most attractive sand control techniques [1]. Although, over the years, a large number of conceptual, analytical and numerical models for sand production prediction have been developed, see e.g. [2–10], the value of these models may still be questioned, considering the discrepancy observed between the model predictions and field observations. To improve and validate the sand prediction models, reliable sand production data are indispensable. The sand production data available can be divided into laboratory sand production test data and field sand production data collected from real wells. Laboratory sand production tests typically concern small-scale simulation of flow through perforations or cylindrical cavities in stressed cylindrical samples (see e.g.[11]). Advantages of such laboratory tests include the controlled stress and pressure boundary conditions, the extensive monitoring facilities available and the simple geometry used, which facilitates interpretation of the experiments. Field observations involve far more complex situations (e.g. perforation interaction), with many uncertainties concerning the actual downhole situation and only limited possibilities of imposing prescribed boundary conditions. Nevertheless, interpreting and predicting such field observations are the prime objective of sand prediction modeling. P. 325^
...SPE Society of Petroleum Engineers SPE 21424 Well Test Analysis of a Well With Multiple Horizontal Drainholes M. Karakas, Schlumberger, and Y.M. Yokoyama...th horizontal drainholes, each in a separate layer, were drilled from the In this paper, we present production test results from existing casing of this well. In order to evaluate the a well which have been recently...izontal completion, the well completion. The subject well K-B produces from a was subjected to four production tests before and limestone reservoir located in the off-shore divided immediately after the drillin...
...2 WELL TEST ANALYSIS OF A WELL WITH MULTIPLE HORIZONTAL DRAIN HOLES SPE 21424 Some of these zones have been det...a stimulation treatment by acidizing, economical vertical direction, vertical flow barriers play an production rates could not be attained from this well. important role in the ...production performance of In June 1984, a workover was conducted to improve individual drainholes. In particul...
...4 WELL TEST ANALYSIS OF A WELL WITH MULTIPLE HORIZONTAL DRAINHOLES SPE 21424 To verify the results, a pressure ...corporate the complete flow completion. A large negative total skin (about -6.3) history during the test. As shown in Fig. 5, the model also confirmed this finding. After the flow response is in a perfect...ained using relevant equations for each flow regime. In these analyses, no a priori While this well test clearly confirmed the existence assumption was made about the producing length (Lp) of the vertical...
SPE Members Abstract This paper presents interpretation of several transient tests conducted in a well with multiple horizontal drainholes. The subject well is located in the offshore divided zone of Saudi Arabia and Kuwait and was initially completed as a vertical producer. Recently, two medium-length horizontal drainholes, each in a separate layer, were drilled from the existing casing of this well. In order to evaluate the effectiveness of the horizontal completion, the well was subjected to four production tests before and immediately after the drilling of each drainhole. These flow tests were analyzed in detail to determine important reservoir and production characteristics. The observed pressure responses are compared with those obtained from analytical and numerical models. A discussion on the practical aspects of well test interpretation in horizontal drainholes is also provided. Numerical simulations show that, for transient analysis purposes, most multiple drainhole systems can be approximated by an equivalent single-layer, single-drainhole systems. Additionally, the results demonstrate the importance of drain hole orientation when the vertical communication between the producing layers is not restricted by flow barriers. Introduction The capability of completing a layered reservoir with several short-radius drainholes, each draining a different layer, provides reservoir and production engineers with new possibilities to enhance oil recovery and for better reservoir management. Proven economical, multiple horizontal drainholes offer a viable stimulation alternative in certain reservoirs where the formation characteristics and/or the possibility of water or gas encroachment preclude the use of conventional techniques. In this paper, we present production test results from a well which have been recently converted into lateral completion. The subject well K-B produces from a limestone reservoir located in the off-shore divided zone of Saudi Arabia and Kuwait. Some of the reservoir and production aspects of this field were previously discussed in an earlier paper. In order to assess the feasibility of lateral completions, K-B, originally a vertical producer, was selected as a pilot well for horizontal drilling. With this objective, two vertically displaced drainholes, each producing from a different layer, were drilled from the existing casing of this well. In order to evaluate the productivity of these drainholes, K-B was subjected to four production tests before and immediately after the drilling of each drain hole. WELL AND RESERVOIR CHARACTERISTICS The reservoir is of a depletion type without any water or gas cap drives. Because of the unfavorable fluid properties (relatively viscous oil with little solution gas), the well productivities play an important role in maintaining economical oil production from this field. Based on available open-hole data, the reservoir has been divided into several productive zones (layers). P. 715^
- Asia > Middle East > Saudi Arabia (0.86)
- Asia > Middle East > Kuwait (0.54)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Khafji Field (0.99)
- Asia > Middle East > Kuwait > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Khafji Field (0.99)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
...The First Long-Term Horizontal-Well Test in the Troll Thin Oil Zone S.C. Lien, Knut Seines, S.O. Havlg, SPE, and Torgeir Kydland, SPE, Nors...roduction the well had produced 1 043 000 stock-tank m 3 of oil and the water cut had stabilized production test was performed The Troll field, located below 300 m of at about 35 %. water offshore Norway (Fig. 1)... oil zone Background a large gas cap and an active aquifer. In the reserves. The oil column in the test westernmost fault block of the field, the The Troll field covers 700 km 2. The estimated area i...
...ll locations, Troll field. oil province, 8 to 15 m in the Troll West properties with respect to oil production. gas province, and 0 to 3 m in Troll East. Although the oil zone is generally thinner The Troll res...reservoir rock, and a (OWC). The relative permeability to water province). Conventional short-term production at residual oil saturation (25 %) is low, from thin 011 column,... tests have been carried out in... all wells. 0.05 to 0.40. Test rates from 600 to 1,200 stock-tank development with m 3/ d were obtained in the Southern oil hor...
...273.75 819 1131 17.5 2428 3840 29!1 3.0 3.4 365 776 1075 17.8 2360 3828 31:0 3.0 3.6 Cumulative oil production after 365 days. stock-tank m 3 /d 0.33 10" 1.12x106 3.6 ing from detailed single-well modelin...perform a second horizontalwell full-field simulations. to those in a development with 24 vertical test in Troll. This ...test was performed All the oil ...
Summary An 11-month horizontal well production test was performed offshore Norway inthe giant Troll gas field to prove performed offshore Norway in the giant Trollgas field to prove possible thin oil zone reserves. The oil column in the testarea possible thin oil zone reserves. The oil column in the test area is only 22 m, and the 500-m horizontal well was positioned 4 m from the water zone and18 m from the gas zone. The well, tied into production and testing ship Petrojarl 1, was put on production in production and testing ship Petrojarl 1, was put on production in Jan. 1990, The initial oil rate from the horizontalwell was more than four times higher than that of a vertical well in the samearea, Test results show that horizontal wells represent a viable technology foreconomic oil production from the thin oil zone in the Troll field. Introduction The Troll field, located below 300 m of water offshore Norway (Fig. 1), contains 0- to 26-m-thick oil rims sandwiched between a large gas cap and anactive aquifer. In the westernmost fault block of the field, the Troll West oilprovince, the oil zone is the thickest, 22 to 26 m. The oil in place (OIP) ofthis province is estimated to be 121 × 10(6) stock-tank m3. The oil in the Troll West oil province is located in high-quality sands withpermeabilities from 3,000 to 10,000 md. The oil production is limited by gasconing, resulting in rapidly production is limited by gas coning, resulting inrapidly decreasing oil rates. Developments by vertical wells therefore haveconsistently exhibited marginal economy. Horizontal wells are known to improve well productivity and to reduce water-and gas-coning problems. The Helder field, offshore The Netherlands, wasredeveloped in 1987–88 with 10 horizontal wells. Results show improvedvolumetric sweep, reduced water coning, and productivities up to 20 timeshigher than for vertical wells. In the Prudhoe Bay field in Alaska, manyhorizontal wells have been drilled. A 5-mm-long horizontal well in this fieldyielded productivities 1.5 to 3 times that of vertical wells. The wells alsoare successful in reducing gas coning. In the Troll field, pretest simulation studies indicated that developmentbased on 500-m horizontal wells could offer an economically attractive oildevelopment. Because of the 300-m water depth, highly unconsolidated reservoirrock, and a thin oil column, however, development with horizontal wells wasconsidered a high-risk project. To confirm the horizontal-well potential and long-term behavior, and therebyreduce the risk involved, a decision was made in June 1989 to perform an8-to-12-month production test with a 500-m horizontal well in the oil zone ofthe Troll West oil province. province. The well, operated by Norsk Hydro A.S., was completed in Dec. 1989, and production from the test ship began in Jan.1990. When the test concluded after 11 months, the well had produced 1 043 000stock-tank m3 of oil and the water cut had stabilized at about 35%. Background The Troll field covers 700 km2. The estimated gas in place (GIP) and OIP are1670 × 10(9) std m3 and 615 × 10(6) stocktank m3, respectively (Fig. 2). Twomain north/south faults divide the field into three provinces: Troll West oilprovince, Troll West gas province, and Troll East (Fig. 2). The Troll West oilprovince is province, and Troll East (Fig. 2). The Troll West oil province isinto the Southern and the Northern oil provinces (Figs. 3 and 4). Concession Block 31/2 (Fig. 2), operated by A/S Norske Shell, was awarded in1979. Blocks 31/3, 31/5, and 31/6 were awarded in 1983 with shared operatorshipbetween Norsk Hydro A.S., Den norske Stats Oljeselskap A.S., and Saga Petroleum A. S. Phase 1 of the Troll development, as proved in 1986, calls for gas Phase 1 of the Troll development, as proved in 1986, calls for gas production to startfrom Troll East in 1996. Before the horizontal test production to start from Troll East in 1996. Before the horizontal test well, 26 exploration wells hadbeen drilled within the four blocks; hydrocarbons were encountered in 22 wells. Two-dimensional seismic surveys Cover all four blocks. To select the horizontalwell location accurately, a 3D seismic survey was carried out during the summerof 1989. Reservoir Description The Troll field is contained within three easterly tilted fault blocks(Figs. 2 and 3). The reservoir interval is of Middle to Upper Jurassic Age, andthe reservoir sediments consist of clean, medium to coarse sand interbeddedwith micaceous and silty, very fine to fine sand. These sediments are generallyvery poorly consolidated. A typical feature of the reservoir sediments in the Troll field is thenumerous calcite-cemented layers occurring in all lithologies in all wells. There are two classes of calcite-cemented layers: extensive (up to severalkilometers) wide sheets found at the boundaries of the geological zones and theless extensive (1 to 100 m) calcite-cemented layers located within thegeological zones. JPT p. 914
- Europe > Norway > North Sea > Northern North Sea (1.00)
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.54)
- Geology > Mineral > Carbonate Mineral > Calcite (0.67)
- Geology > Structural Geology > Fault (0.44)
- Geology > Rock Type (0.34)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Fensfjord Formation (0.99)
- (11 more...)
...Predicting sand production Predicting whether a well will produce fluids without producing sand has been the goal of many co...he best way of determining the need for sand control in a particular well is to perform an extended production test with a conventional completion and observe whether sand ...production occurs. Normally, it is not necessary to predict sand ...
Predicting whether a well will produce fluids without producing sand has been the goal of many completion engineers and research projects. There are a number of analytical techniques and guidelines to assist in determining ifsand control is necessary, but no technique has proven to be universally acceptable or completely accurate. In some geographic regions, guidelines and rules of thumb apply that have little validity in other areas of the world. Predicting whether a formation will or will not produce sand is not an exact science, and more refinement is needed. Until better prediction techniques are available, the best way of determining the need for sand control in a particular well is to perform an extended production test with a conventional completion and observe whether sand production occurs.
- North America > United States > California > Sacramento Basin > 4 Formation (0.99)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- Well Completion > Sand Control (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Solids (scale, sand, etc.) (0.81)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.51)
- Information Technology > Knowledge Management (0.41)
- Information Technology > Communications > Collaboration (0.41)
Cased Hole Production Testing with Extended Spacing Wireline Formation Testers
Charupa, M.. (Schlumberger) | Khaziev, M.. (Schlumberger) | Blinov, V.. (Schlumberger) | Weinheber, P.. (Schlumberger) | Oreshko, I.. (Schlumberger) | Goitia, V. H. (Eurotek Yugra) | Eslami, B.. (Eurotek Yugra) | Arnez, R.. (Eurotek Yugra)
...SPE-176542-MS Cased Hole Production Testing with Extended Spacing Wireline Formation Testers M. Charupa, M. Khaziev, V. Blinov, P. Wei...operator is left to either forgo the information or acquire the data in cased hole. Perforating and production testing in cased hole can be time consuming and expensive especially when there are multiple layers... to be tested. This can be mitigated by using wireline formation testers (WFT) in cased hole to test individual layers, but these testers have traditionally been limited in their possible interval len...
...uch as our example, it is not practical from time and money point of view to perform the full scale test. In this case the WFT option is ideal. Additionaly the wireline formation tester gives us the oppur...tunity to record high quality pressure data, since it has downhole shut in valve and to test multiple zones in one descent. Also the WFT can analyse the fluid in the flow in real time so there... is no need to deploy a production logging toolstring or have a separator on surface. This can be useful on remote or offshore project...
...ws additional spacers to be included in between the two tools to extend the interval of a potential test zone to virtually any length. With two pairs of packer elements the ...test interval or spacing length effectively becomes the distance between the topmost and bottommost pack...
Abstract Wireline formation testing in open hole can yield robust and reliable information about reservoir fluid type and productivity. However, operational or logistical concerns can sometimes preclude gathering a full open hole formation tester data set. In this case the operator is left to either forgo the information or acquire the data in cased hole. Perforating and production testing in cased hole can be time consuming and expensive especially when there are multiple layers to be tested. This can be mitigated by using wireline formation testers (WFT) in cased hole to test individual layers, but these testers have traditionally been limited in their possible interval length. In this paper we discuss cased hole wireline formation testing with a unique configuration of the WFT that allows testing intervals much greater than previously possible. Wireline formation tester tools with straddle packers are typically limited to about 1-m spacing between the packers. With special adaptors spacings up to 3 m have been accomplished. However, when perforated intervals are longer than this the straddle packer is not an option: it is usually inadvisable to set the elements across perforated casing and cracks in the perforated cement can make the fluid typing ambiguous. This paper discusses a method whereby two separate straddle packer tools are combined and allow a significantly longer interval to be tested. We present a case study where the extended interval was tested and flowed for several days with the formation tester and a confident determination of fluid type performed. Additionally, a long build-up time enabled us to derive a robust estimation of permeability. The operation was concluded in three days versus the ten days of rig time that would have been expected for a cased hole production test. We also show how this method can be extended to longer intervals in both open and cased hole. We conclude that this method is should be considered for zones that could not be tested in open hole but are not worthy of a full production test in cased hole. Although cased whole WFT operations with straddle packers have been reported in the literature this is the first instance of a double WFT tool arrangement that allows testing layers of significant perforated length. Operational guidelines and environmental limitations are also discussed.
- Oceania > Australia (0.29)
- Asia > Russia (0.29)
- North America > United States (0.28)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Purovsky District > West Siberian Basin (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Kamenny License > Krasnoleninskoye Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Kamennaya Area > Krasnoleninskoye Field (0.99)
- (4 more...)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
...SPE 68688 PRODUCTION ENHANCEMENT IN THE BELAYIM FIELDS: CASE HISTORIES 5 designs. Once the design is fixed, manufacturi...l productivity, a deep penetrator will need stressed conditions. Unconfined compressive strength of test to shoot to a depth at least 1.5 times that of the wellbore targets is a minimum of 3300 psi, repr... Currently, all wells use process takes place in less than one millisecond. The explosive ESP's for production. During the forty years plus of field provides energy to collapse the liner and form a fast-moving,...
...6 H. ELSHAHAWI, M. SAFWAT, S. SISO, M. SAMIR SPE 68688 production capacity of the wells was derived from one or more water. The lack of success of these chemicals ca...essure sensors several strata with widely varying petrophysical parameters 2. Data measured during production test (Hall, 1986). 3. Data measured by PLT (using Y-tool) 4. Slug ...test analysis E) Deep-penetrating perforating has been the most successful 5. Back calculation using an...
...SPE 68688 PRODUCTION ENHANCEMENT IN THE BELAYIM FIELDS: CASE HISTORIES 7 reached roughly 30-40 m3/d in the two wells an...ing, with deep penetrating guns and to perform a complete stimulation and/or injection operations. production test using a Y-tool string so as to record a ...production log and perform pressure build-up. - Skin is the most effective way to represent productivity impa...
Abstract Inadequate productivity of perforated wells has been a major concern since the introduction of cased completions. Petrobel company, operating in the Belayim fields of Sinai, Egypt, and responding to an unpredictably fast decline in field production, launched an initiative in 1996 to identify the under-performing perforated wells in order to plan remedial actions. Since the vast majority of the wells were under artificial lift, this involved the integration of data from various sources. The study revealed that the majority of wells in the field were in fact suffering from excessive damage. Wells were then categorized based on the value of their completion factors (the ratio of actual to theoretical productivity indices), and the potential sources of damage were identified for each category. This was accomplished using techniques such as nodal analysis and skin modeling. One of the most successful techniques used to cure the damage was the re-perforation of the damaged wells with deep-penetrating perforating charges. Until the use of this technique, and even with attempted improvements in other operating parameters, field performance had continued to fall short of theoretically predicted results. This paper highlights the origin and development of formation damage in the Belayim fields, and how this damage was attributed to different damage mechanisms using a novel combination of nodal and damage analysis techniques. It also presents some cases of dramatic productivity enhancement due to the use of these techniques and the introduction of deep penetrating perforating. Introduction Inadequate productivity of perforated completions has always been a major concern for oil companies. Many wells have been abandoned prematurely due to reaching their economic limits too early. Formation damage can be defined as any barrier within the confines of the near wellbore reservoir or wellbore completion interval that restricts the natural production of formation fluids. In the following, potential sources of damage during various well operations are outlined. A) Drilling Damage Drilling damage results from the invasion of the formation by drilling fluid particles or by drilling fluid filtrate. The depth of particle invasion is usually small, ranging from 1 to 12 inches (Gatlin, 1960). The relative sizes of the fines and the pore throats are the primary factor in determining how much formation damage will occur. External bridging will occur if the median particle size is larger than 1/3rd of the mean pore throat size, causing little or no damage. Particle sizes in the range of 1/3rd to 1/7th of the mean pore throat diameter will result in shallow invasion but is the most damaging type of particle invasion. Finally, particle sizes less than 1/7th of the mean pore throat diameter are usually small enough to readily flow through the pore throats without causing significant plugging (Van Poolen, 1966). Drilling mud filtrate will invade the formation to a greater depth than drilling mud particles, with depths of invasion of 1 to 6 ft being common (Hassen, 1980). Increased water saturation around the wellbore, emulsion formation, and clay dispersion are some of the formation damage mechanisms that can take place as a result of drilling fluid invasion. The volume of fluid lost prior to the formation of the filter cake (spurt loss) is related to the permeability of the formation. If adequate bridging agents are not present, particularly in high permeability formations, the entire fluid may be lost during the spurt period. Once an effective filter cake is formed, constant pressure filtration occurs, and the thus much lower rate of leak-off is controlled by filter cake permeability (Hassen, 1980).
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
- Geology > Mineral (0.67)
- North America > United States > Illinois > Marine Field (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Rudeis Formation (0.99)
- Africa > Middle East > Egypt > Gulf of Suez > Gulf of Suez Basin > Belayim Field (0.98)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Egypt Field (0.97)
...SPE 30841 Progressive Production Technology in Complicated Dispersed Small Oil and Gas Fields Sun Tiesen, Su Shulin, Liu Houfa & D...u Shanbin No.9 Oil Production Company, Daqing Petroleum Administrative Bureau Copyright 1995, Society of Petroleum Engineers. In... in the west peripheral area of Daqing oilfield has led to development of a system of progressive production technology. Experience shows that this technology system is feasible and of good practical value t...
...SPE 30641 production wells, and verified the structure, reservoir layer characteristics and the distribution pattern of... Main Techniques In Study And Application 1. Reservoir Prediction Techniques. In the progressive production of the complicated oil and gas fields, besides conventional reservoir prediction based on drilling...servoir parameters and porosity) and characteristics are mainly made by seismic technique, modern production test technique, sedimentary facies study, core analysis, etc. The prediction method is adapted to the ...
...il, gas and water in the entire oilfield. All of these studies have better guided the progressive production of the Aogula Oilfield. (3) Completion Techniques. During drilling, mud density is must be kept a...density, deeper penetration, larger hole diameter, and no plugging. Perforation was combined with production testing, so the well was forced down to perfect under balance perforation (Table 1) conditions. I...n the early days after perforation, the well flowed, and the converted production was 46.5 t/d, the productivity index of net effective thickness was up to 3.212 U(d.m.MPa). Conv...
Abstract Producing experience in complicated, dispersed small oil and gas fields in the west peripheral area of Daqing oilfield has led to development of a system of progressive production technology. Experience shows that this technology system is feasible and of good practical value to the production of a complicated small oilfield. Introduction Complicated oil and gas fields have following characteristics, multiple oil-bearing strata, stacked traps of many types, and complicated relationships between oil and water both vertically and horizontally. It is impossible to develop complete knowledge of complicated reservoirs in a short period of time. Profitability is enhanced if the oil and gas-bearing reservoirs, which are best understood and have the better productivity are developed first. During formal production stage, various advanced prediction and completion technologies should be used and the all oil and gas accumulations should be developed, connected and deeply understood. New series of oil-bearing strata and traps should be developed by stages. This kind of development is called progressive production, and a whole set of technology based on it is called progressive production technology. In recent years, by applying progressive technology, we have developed five oil and gas fields in the west peripheral area of Daqing Oilfield (Fig. 1). Based on the production example of Aogula Oilfield, this paper gives a summary and review for the gradually developed and perfected progressive production technology. Overall Arrangement Of Progressive Production Before deciding to conduct progressive production in a complex oil and gas field, systematic study, evaluation and analysis must be made. Overall arrangements must be determined by fully using available exploration data. Progressive production in Aogula Oilfield started in 1988. According to the evaluation of detailed exploration in 1985, this oil field could be divided into four areas. (Fig. 2). On the west side of the Aogula major fault they are, Ta 20 well area, Ta 5 well area, and Ta 3 and Ta 301 well areas. On the east side of the Aogula major fault there is the Ta 2 well area. The main part of the field is on the west side of the major fault, with 77.1% of the OOIP of the whole oil field. For the three areas on the west side of the major fault, from north to south, the geological conditions become more complex. The prospecting degree of the north Ta 20 well area was relatively high. At that time, three information wells had been drilled. Many layers with large thickness had been penetrated and single well productivity was relatively high. The vertical distribution of oil, gas and water was recognized relatively clearly. In the middle Ta 5 well area, there was only one exploration well, which suffered from mass channeling as a result of a bad cement job.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
...ervoir. In May of 1991, after of drilling of the first Mexican horizontal well (Agua Fria 801-H), a test pressure-...production The productivity of horizontal wells can be greater than the using a hi-res tool (PLT) was designed...nt, allowed that area of communication with the producing formation, cross the data of the pressure test showed the characteristic behavior perpendicularly to systems of natural fractures, commonly of the...
...SPE 59062 EVALUATION OF HORIZONTAL WELL PRODUCTION 3 oil, to optimize the ...production an artificial system of rise of Also, to prove the ...production capacity of the well, different the fluid by pneumatic pumping has been implanted. stages of B. N. ...
...SPE 59062 Evaluation of Horizontal Well Production R. Leon-Ventura, G. Gonzalez-G. and H. Leyva-G./Pemex-E&P. Copyright 2000, Society of Petroleum E...rained volumes want to be increased or to reduce On the other hand, an stimulation can increase the production investments with additional drilling wells, we can use of a vertical well, but after a time the rat...e declines quickly. In horizontal wells as a good alternative for optimum general, the production rates of horizontal wells are exploitation of the oilfields. This is supported because the signific...
Abstract When drained volumes want to be increased or to reduce investments with additional drilling wells, we can use horizontal wells as a good alternative for optimum exploitation of the oilfields. This is supported because the horizontal wells productivity becomes higher than in a vertical, due to that they communicate a large area of the producing formation, cross natural fractures, reduce pressure drops and advances of water-oil or gas-oil contacts are delayed. In Mexico, several horizontal wells have been drilled in different kinds of formations, which initially have responded with production expectations. However, after a short production time, productivity conditions have been reduced significatively, which have practically condemned the use of this technology in the development of hydrocarbons exploitation. Therefore, in this work a comparative evaluation of the initial productivity of horizontal wells with respect to vertical wells is made to know their behaviour and to identify design parameters that govern the feasibility of obtaining successful horizontal wells. Analysis of horizontal wells on Agua Fria, Cantarell and Abkatun fields (North, Northeast Marine and Southwest Marine Regions, respectively) are included in this study. Introduction In last years many horizontal wells around the world have been drilled 1,2. The main objective of a horizontal well is to increase the contact area with the reservoir and therefore, to improve the productivity of the well. In general terms, the horizontal wells are effective in reservoirs of small thickness, in naturally fractured formations, in thick reservoirs and with problems of water and gas coning. It has been demonstrated that one horizontal well behaves in equivalent form to a vertical well with a totally penetrating fracture; therefore, actually a horizontal well instead of fracturing a vertical well could be contemplated3. In a naturally fractured reservoir, a horizontal well will cross several fractures and then it will drain more effetively to the formation. On the other hand, an stimulation can increase the production of a vertical well, but after a time the rate declines quickly. In general, the production rates of horizontal wells are significantly higher that those of stimulated vertical wells. Therefore, the behaviour of its production has improved considerably the economic view and supports the development of the reservoirs exploitation 4. In this decade the interest of the application of horizontal wells has been accelerated which had mainly to improve of drilling and completion technologies, which has allowed to increase the efficiency and the economy in the hydrocarbons recovery 1–3. The horizontal drilling can be applicable in any stage of hydrocarbons recovery: primary, secondary and enhanced 5. At this moment the reservoirs exploitation by means of horizontal wells has a great strategic value and offers benefits, such as: fast recovery of investments, increase of recoverable reserves, reduction of the production costs and minor number of wells or platforms by field. This work has like main objectives, to emphasize the excellent aspects that govern the design of the horizontal drilling wells, to make a comparative study of the conditions of different horizontal well production and specially, the evaluation of the present conditions of production of horizontal wells developed in Mexico.
- North America > United States > Texas (1.00)
- North America > Mexico > Gulf of Mexico > Bay of Campeche (0.67)
- North America > Mexico > Gulf of Mexico > Tampico-Misantla Basin > Chicontepec Basin > Agua Fria Field (0.99)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Northeast Marine Region > Cantarell Field (0.99)
- North America > Mexico > Gulf of Mexico > Bay of Campeche > Sureste Basin > Campeche Basin > Abkatun-Pol-Chuc Field (0.99)
- Oceania > Australia > Victoria > Bass Strait > Gippsland Basin (0.93)
...SPE-178298-MS Gas well Test Interpretation: Niger Delta Field Experience P. P. Obeahon, O. Daodu, and A. Sedgwick, Shell Petro...abstract must contain conspicuous acknowledgment of SPE copyright. Abstract This work details how production data, well ...test analysis and PVT data analysis can be used to evaluate the effects of near wellbore condensate accu...
...urface and operations personnel. This paper discusses the results of integrating findings from well-test analysis, geoscience data, and pressure-volume-temperature (PVT) relationship of the reservoir flui... The primary focus is on demonstrating the strength of multidisciplinary interpretation of gas well-test data to maximise information on the reservoir characteristics, as well as distinguish between Darcy...ct optimum productivity of the well, MRT was conducted after completing the well to acquire surface production data. Total well clean-up lasted for 24.5 hours and then the well was shut-in for 10-hour stabiliza...
... system. Notwithstanding that the drawdown is acceptable, the impact of the high drawdown on future production and possible causes were investigated as one or some combinations of the following. Figure 3--Matc...hed IPR/VLP Curve for Well-3 Water Blockage/coning: During the testing, water production was in the range 0.35-0.45bbl/MMscf. Given the low water-...production, water blockage or coning was regarded as an unlikely cause. Scales: Statistics on scale-formation ...
Abstract This work details how production data, well test analysis and PVT data analysis can be used to evaluate the effects of near wellbore condensate accumulation on well productivity for a green field in the Niger Delta. The field, comprising shore-face deposits that were later cut by channels in a high-energy deltaic setting. Prior to this study, six wells had been drilled. Wells -1 and -2 had exploration and appraisal objectives while wells -3, -4, -5 and -6 had development objective. After drilling wells -3, -4, -5 and -6, MRT were conducted on these wells with the key objective of verifying analogue based well deliverability. The following conclusions arise from the interpretation of the test data. Well-3 will deliver at a lower rate of 50MMscf/day as opposed to the pre-test estimate of 100MMscf/day. This is due to higher Darcy and non-Darcy coefficients. Furthermore, flowing bottom hole pressure recorded during testing and from the first four months of production indicates that the reservoir was been depleted below the dew-point pressure of 4724 psi by about 100 psi. These observations, in combination with declining productivity index and producing condensate-gas ratio suggest that condensate dropout is most likely responsible for the high skin, hence well-3 potential was revised from MRT interpreted estimate of 89MMscf/day to 50MMscf/day. This decrease in well potential from 100MMscf/day to 50MMscf/day decelerated gas recovery by about 3 years. Well-4 data interpretation indicated low non-Darcy skin and Darcy coefficient. Single pressure build-up (PBU) interpretation indicated pressure leaks into the casing-tubing annulus, an inference substantiated by the observation of consistent high casing-head pressure in the well. Possible causes of high casing-head pressure were investigated and attributed to poor tubing connection. Both wells 5 and -6 penetrate the same sand. A four-point test was performed on Well-6 while performing PBU on Well-5 hence no pressure stabilization on these well due to Interference effect. Interpreted results indicates that Well-5 has a higher Darcy skin and lower non-Darcy coefficient compared to Well-6, with both wells expected to deliver the planned offtake rates of 100MMscf/day within acceptable drawdown limits. This work identifies dew point pressure as an extremely important factor to consider when designing gas well test, generating deliverability envelopes and optimizing condensate recovery as productivities can be reduced by 50% when condensate banking begins.
- North America > United States (0.94)
- Africa > Nigeria > Niger Delta (0.61)
- North America > Canada > Saskatchewan (0.40)
- (2 more...)
Underbalanced Drilling For Production Enhancement in the Rasau Oil Field, Brunei
Sarssam, Mark (Brunei Shell Petroleum) | Peterson, Russell (Brunei Shell Petroleum) | Ward, Mike (Brunei Shell Petroleum) | Elliott, Dave (Shell Global UBD Implementation Team) | McMillan, Scott (Halliburton Energy Services, Inc.)
...es were as follows: Detailed UBD Procedures were developed, along with sitelayout/hazardous-area - Test the applicability of UBD technology drawings and process-flow diagrams. - Determine if there are f...wire-wrapped screens UBD equipment configuration used for this project. The and a single tubing and production packer (see Fig. 3). major pieces of equipment were as follows: A key element of the preparation fo...d oil and water were exported to the field fluids to mitigate formation damage and to ensure that a production facilities via a temporary pipeline. Gas was flared suitable underbalanced pressure window could be...
... crude and produced water back to the field formation drilled overbalanced, before the pressure was production facility, via a high-pressure gathering system. reduced to attempt underbalanced operations. Unfort...d back to the shoe, and target reservoir was drilled before the pipe became stuck, and a three-rate production test was performed. The well communications with the downhole tools were lost. The string productivity i...i. was freed, but subsequently became stuck on several The average gas/oil ratio (GOR) over a total test period of nine occasions while tripping out. Once recovered and inside hours was 968 scf/B with no ...
...A completion tubing string was run into the well as UBD equipment was flushed UBD Well Preliminary Production Test Results and rigged down. The inflatable plug was retrieved through Wells 2 and 3 were flow tested ...e the final Trial Well 3 - Summary of Operations productivity. In both cases, a 3-stage multi-rate test was The third and final UBD trial well (RS39) was also planned as completed. Results were very enco...lems of shoe, as the pre-drilling estimate of reservoir pressure had failure of the valves, loss of production of a prolific sand been 1870 psi. (unable to get screens to TD) plus autopacking and solids After ...
Abstract Underbalanced drilling (UBD) technology has been gaining in popularity around the world because of its capability to reduce or eliminate formation damage, to increase production rates, and in some cases, increase the volume of recoverable reserves. The technology is applicable to fields where formation damage is a concern or where problems such as severe fluid loss, differential sticking, steering problems or slow drilling rates are encountered with conventional drilling. With underbalanced drilling, the formation pressure is greater than the hydrostatic pressure, allowing hydrocarbons to flow into the wellbore during drilling. This prevents potentially damaging drilling fluids and drilled fines from penetrating the producing formation. In previous experiences in the field using traditional drilling methods, considerable formation damage had been experienced, and although UBD had never been attempted in the area before, Brunei Shell Petroleum and its government partner decided to use this technology in a three-well trial in the Rasau field, located onshore in Kuala Belait, Brunei. Of the three wells attempted during this UBD trial one well could not be drilled due to catastrophic borehole collapse. The other two wells were successfully drilled to depth using UBD techniques; however, multiple hole volumes of solids were produced during drilling and production testing, indicating borehole stability problems. Production rates observed after drilling to TD and prior to running completions indicated zero formation impairment, with well productivity exceeding expectation; however, during the completion phase, mechanical problems occurred, and post completion well tests indicated productivity reductions of 60 to 70% compared with the pre-completion tests. This paper discusses the planning, drilling, results, highlights, and lowlights from this UBD trial, along with learnings and recommendations for future application of the technology. The execution of the program led to a sharp learning curve, and the development of recommendations that can be applied to future operations in this field. These primarily relate to well (construction) design, drilling procedures, equipment design, rig-up and rig-down optimization between wells, and completion design. Introduction The Rasau field structure is a local accumulation in a major anticline ridge extending from Miri, Malaysia to Seria, Brunei. The accumulation is divided into two fault systems, one trending in a southwest to northeast direction and the other in an east to west direction. The Rasau field has been on production since 1983 and there are currently 27 producing wells. The sandstone reservoirs are generally of moderate quality (1–100 md), and are of shallow marine origin, resulting in a laterally extensive stacked sequence. The producing reservoirs, typically located at a depth of 4900ft - 6500ft, contain saturated light oil (40°API) with varying sizes of gas cap. The drive mechanisms are reservoir specific and are typically a combination of gas cap expansion, solution gas drive and aquifer influx. To date, there have been no secondary recovery schemes implemented in the Rasau field. The 3-well trial project incorporated several major challenges that had to be addressed through the initial planning / design phase and risk/hazard assessment processes. To minimize formation damage and reduce cost, produced oil and gas were chosen as the drilling fluids. The wells were drilled at high angle through the target reservoirs, cutting through the many thin layers of pay to maximize formation exposure. Due to the layered nature of the reservoir, a moderate amount of shaley formation was expected within the planned trajectories (up to 50%), the stability of which was to be assessed as one of the trial objectives. The stability of this material was to prove a key factor during the underbalanced operations, and is thought to have been the cause of significant problems due to borehole breakout and collapse. Fig. 1 shows the location of the Rasau trial wells, and Fig. 2 shows the trial-well trajectory.
- Geology > Structural Geology (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)